LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2000, the Company had working capital of $147.8 million including cash and cash equivalents of $107.7 million. This is a decrease in working capital of $19.3 million from December 31, 1999. This decrease primarily reflects the Company's increased activity in the wholesale power market.

Cash generated from operating activities was $239.5 million, an increase of $26.5 million from 1999. This increase was primarily the result of increased profitability including the favorable settlement of a lawsuit. In addition, accounts payable increased due to increased wholesale power purchases driven by the Company's expansion of its wholesale power marketing operations. This increase was partially offset by an increase in the Company's receivables. Unrecovered purchased gas adjustments and accounts receivable from utility customers increased as a result of higher gas prices. In addition, accounts receivable increased as a result of increased wholesale electricity sales.

Cash used for investing activities was $157.5 million in 2000 compared to $55.9 million in 1999. This increased spending reflects $13.3 million related to the acquisition of transmission assets (see "Acquisition of Certain Assets and Related Agreements" below), combustion turbine option payments of $13.0 million, the expansion of the electric distribution system at a cost of $13.7 million and the gas transmission and distribution systems at a cost of $10.1 million to serve new load and for reliability purposes, an investment in an internet gateway service provider of $10.0 million and additional funding and realized gains in the decommissioning trust of $9.3 million. Cash used for investing activities in 2000 includes the $6.7 million of costs related to the acquisition of Western Resources electric utility assets. In addition, in 1999 the Company liquidated certain insurance-based investments in the nuclear decommissioning trust of $26.6 million.

Cash used for financing activities was $94.7 million in 2000 compared to $98.0 million in 1999. This decrease reflects $26.6 million of loan repayments associated with nuclear decommissioning trust activities in 1999, partially offset by the issuance of $11.5 million of 6.60% Pollution Control Revenue Bonds in 1999 and increased common stock repurchases in 2000 (see "Stock Repurchase" below).

Capital Requirements

Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. In addition, the Company anticipates significant expenditures to expand its generation capabilities. Projections for total capital requirements and construction expenditures for 2001 are $353 million and $347 million, respectively. Such projections for the years 2001 through 2005 are $1.45 billion and $1.42 billion, respectively. These estimates are under continuing review and subject to on-going adjustment (see "Competitive Strategy" above).

The Company's construction expenditures for 2000 were entirely funded through cash generated from operations. The Company currently anticipates that internal cash generation and current debt capacity will be sufficient to meet capital requirements for the years 2001 through 2005, except as provided for in its proposed plan to separate pursuant to the Restructuring Act (see "Proposed Holding Company Plan" below). 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 February 1, 2001, the Company had $175 million of available liquidity arrangements, consisting of $150 million from a senior unsecured revolving credit facility ("Credit Facility"), and $25 million in local lines of credit. The Credit Facility will expire in March 2003. There were no outstanding borrowings as of February 1, 2001.

The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, results of operations, credit ratings, regulatory approvals and financial market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities, and to obtain short-term credit.

In connection with the Company's announcement of its proposed acquisition of Western Resources' electric utility operations, Standard and Poors ("S&P"), Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch") have placed the Company's securities ratings on negative credit watch pending review of the transaction. The Company is committed to maintaining its investment grade. S&P has rated the Company's senior unsecured debt and its EIP senior secured debt "BBB-" and its preferred stock "BB". Moody's has rated the Company's senior unsecured notes and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "ba1". The EIP lease obligation bonds are also rated "Ba1". Fitch rates the Company's senior unsecured notes and senior unsecured pollution control revenue bonds "BBB-," the Company's EIP lease obligation "BB+" and the Company's preferred stock "BB-." Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

In addition to the impact of the proposed acquisition of Western Resources' electric utility operations, future rating actions for the Company's securities will depend in large part on the actions of the PRC relating to numerous restructuring issues, including the Company's proposed plan to separate the utility into a generation business and a distribution and transmission business as required by the Restructuring Act ("Proposed Plan"). The Company believes, based on its Proposed Plan (see "Proposed Holding Company Plan" below), that UtilityCo and PowerCo will both receive investment grade credit ratings, however, such ratings will be contingent upon many factors that have yet to be determined. Fitch announced publicly that assuming the Company implements its Proposed Plan, it would expect to issue investment grade ratings for UtilityCo, and PowerCo's rating would "border investment grade". Fitch cautioned that ratings for UtilityCo and PowerCo were highly conditional upon reaching assumptions provided by the Company.

Covenants in the Company's Palo Verde Nuclear Generating Station Units 1 and 2 lease agreements limit the Company's ability, without consent of the owner participants in the lease transactions: (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. The Credit Facility imposes similar restrictions regardless of credit ratings.

Financing Activities

In January 2000, the Company reacquired $34.7 million of its 7.5% senior unsecured notes through open market purchases at a cost of $32.8 million.

The Company currently has no requirements for long-term financings during the period of 2001 through 2004, except as part of its Proposed Plan (see "Proposed Holding Company Plan" below). However, during this period, the Company could enter into long-term financings for the purpose of strengthening its balance sheet and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under the Company's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt to capital requirements in certain of the Company's financial instruments would ultimately restrict the Company's ability to issue SUNs.

Proposed Holding Company Plan

On April 18, 2000, the Company filed as an exhibit on Form 8-K, unaudited pro forma financial statements of PowerCo and UtilityCo that give effect to the Company's Proposed Plan. The structure of the Proposed Plan presented in the April 18, 2000 Form 8-K was subsequently revised in October 2000 by the Company. This revised Proposed Plan results in a capital structure for the holding company, PowerCo and UtilityCo similar to the presentation in the Form 8-K. The revised Proposed Plan is subject to regulatory and other approvals as well as market, economic and business conditions. As such, the revised Proposed Plan may be subject to significant changes before implementation and the pro forma financial statements as filed in the Form 8-K may require revision to reflect the final plan of separation pursuant to the Restructuring Act.

The revised Proposed Plan assumes that the separation required under the Restructuring Act will be accomplished as follows: PowerCo will transfer its regulated assets to a wholly owned subsidiary, UtilityCo, in exchange for common stock, UtilityCo preferred stock, UtilityCo senior unsecured notes and cash. UtilityCo will also assume certain liabilities associated with the regulated assets. PowerCo will then dividend the common stock of UtilityCo to the holding company.

The current holders of PowerCo's public SUNs will be offered the opportunity to exchange their approximately $368 million of existing SUNs for $368 million of SUNs issued by UtilityCo with like terms and conditions. The current holders of PowerCo's preferred stock will be offered the opportunity to exchange their approximately $12.8 million of preferred stock for preferred stock issued by UtilityCo with like terms and conditions.

Although there are other alternatives to finance the acquisition of the regulated assets from PowerCo, based on current market, economic and business conditions, the Company currently believes that the foregoing transactions represent the most advantageous way to effect the Asset Transfer. However, the structure of the revised Proposed Plan is subject to change as the regulatory approval process continues and is ultimately resolved. Implementation of the Proposed Plan in 2001 is dependent on the outcome of certain pending legislation which if enacted, would delay restructuring for five more years.

A condition precedent to corporate separation is the obtaining of written consents from PVNGS lessors. As of December 31, 2000, two lessors had signed consents, one lessor has agreed in principle to the terms of the signed consent but had not signed, and two lessors had not agreed to those terms. The signed consents have various financial covenants which limit PowerCo's ability to sell, transfer or convey its assets assuming certain coverage ratios are not met. Additionally, the consents require the holding company to guarantee the leases. The consents and the covenants will not become effective until corporate separation occurs.

Stock Repurchase

In March 1999, the Company's board of directors approved a plan to repurchase up to 1,587,000 shares of the Company's outstanding common stock with maximum purchase price of $19.00 per share. In December 1999, the Company's board of directors authorized the Company to repurchase up to an additional $20.0 million of the Company's common stock. As of December 31, 1999, the Company repurchased 1,070,700 shares of its previously outstanding common stock at a cost of $18.8 million. From January 2, 2000 through March 31, 2000, the Company repurchased an additional 1,167,684 shares of its outstanding common stock at a cost of $18.9 million. The Company has repurchased all shares authorized in March 1999 and December 1999 by the Board of Directors.

On August 8, 2000, the Company's Board of Directors approved a plan to repurchase up to $35 million of the Company's common stock through the end of the first quarter of 2001. From August 8, 2000 through December 31, 2000 Company repurchased an additional 417,900 shares of its outstanding common stock at a cost of $9.0 million. As of February 1, 2001, the Company does not anticipate continuing its repurchase plan given the share price of its common stock.

Acquisition of Certain Assets and Related Agreements

The Company and Tri-State Generation and Transmission Association, Inc. ("Tri-State") entered into an asset sale agreement dated September 9, 1999, pursuant to which Tri-State has agreed to sell to the Company certain assets acquired by Tri-State as the result of Tri-State's merger with Plains Electric Generation and Transmission Cooperative, Inc. ("Plains") consisting primarily of transmission assets, a fifty percent interest in an inactive power plant located near Albuquerque, and an office building. The purchase price was originally $13.2 million, subject to adjustment at the time of closing, with the transaction to close in two phases. On July 1, 2000, the first phase was completed, and the Company acquired the 50 percent ownership in the inactive power plant and the office building. The second phase relating to the transmission assets is expected to close in the first quarter 2001.

In addition, on July 1, 2000, the Company advanced $11.8 million to a former Plains cooperative member as part of an agreement for the Company to become the cooperative's power supplier. Approximately $4.5 million of this advance represents an inducement for entering into a 10 year power sales agreement. Accordingly, the Company expensed this amount in the third quarter as a business development cost. The remaining $7.5 million will be repaid over 10 years. If the cooperative terminates the contract early, the whole $11.8 million advance must be repaid to the Company.

Dividends

The Company's board of directors reviews the Company's dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the extent to which cash flows will support dividends, the availability of retained earnings, the financial circumstances and performance of the Company, the PRC's decisions on the Company's various regulatory cases currently pending, the effect of deregulating generation markets and market economic conditions. The ability to recover stranded costs in deregulation, future growth plans and the related capital requirements and standard business considerations will also affect the Company's ability to pay dividends. In addition, following the separation as required by the Restructuring Act, the ability of the proposed holding company to pay dividends will depend initially on the dividends and other distributions that UtilityCo and PowerCo pay to the holding company.

                                              2000        1999
                                              ----        ----

Common Equity............................      48.6%      46.7%
Preferred Stock..........................       0.7        0.7
Long-term Debt...........................      50.7       52.6
                                              -----      -----
   Total Capitalization*.................     100.0%     100.0%
                                              =====      =====

* Total capitalization does not include as debt the present value of the Company's lease obligations for PVNGS Units 1 and 2 and EIP which was $162 million as of December 31, 2000 and $165 million as of December 31, 1999.

OTHER ISSUES FACING THE COMPANY

THE RESTRUCTURING ACT, THE FORMATION OF HOLDING COMPANY
AND CORPORATE SEPARATION

The Company has filed its transition plan with the PRC pursuant to the Restructuring Act in three parts. In November 1999, the Company filed the first two parts of the transition plan with the PRC. Part one, which has been approved, requested approval to create Manzano and UtilityCo as wholly-owned shell subsidiaries of the Company. Part two of the Company's transition plan requested all PRC approvals necessary for the Company to implement the formation of the holding company structure, the share exchange and the separation plan. Part Two is awaiting a recommended decision by the hearing examiner. Under existing deadlines, the Company must separate its assets no later than August 1, 2001. The Company's management believes that implementation of the separation plan will not occur prior to August 1, 2001, and there is no assurance that implementation of the separation plan will occur by that time. On May 31, 2000, the Company filed with the PRC part three of the transition plan requesting approval for the recovery of stranded costs and other expenses associated with the transition to a competitive market, UtilityCo's rates for retail distribution services, the procurement of "standard offer service" power supplies for customers who do not select a power supplier and other issues required to be considered under the Restructuring Act. The Hearing Examiner has tentatively scheduled hearings on Part three to begin on June 6, 2001. Hearings are expected to last four to six weeks.

On August 17, 2000, the PRC staff and other parties filed a Joint Motion to Defer Commission Decision on Separation of Generation Assets and to extend the Standard Offer Update Deadline. The Joint Motion requested that the PRC not allow separation to occur until after the 2001 legislative session to allow the legislature to determine if any amendments to the Restructuring Act might be necessary in light of the high prices experienced last year in California. The 2001 legislative session began January 16 and ends March 17. On September 11, 2000, the Company filed its response to the Joint Motion, pointing out key differences between New Mexico's Restructuring Act and California's as well as differing circumstances between the two states. On September 26, 2000, the PRC conducted a workshop where numerous interested parties commented on the California experience and its relevance to New Mexico. To date, the PRC has not formally acted on the Joint Motion.

The New Mexico Legislature is currently considering various legislative initiatives that could delay open access and activities under the Restructuring Act, including corporate separation. Legislators are concerned by the turmoil in the California retail energy market. On February 14, 2001, Senate Bill 266, as amended, passed the Senate 39-0. The bill delays implementation of restructuring, including corporate separation, by an additional five years. The PRC would have the authority to delay for another year under certain circumstances. The amended bill would require the PRC to approve a holding company, without asset separation, by July 1, 2001. In addition, the amended bill allows utilities to engage in unregulated power generation business activities until corporate separation is implemented. The cost of new unregulated utility generation resources will serve as a cap on the price of new resources needed to serve retail customers until restructuring is implemented.

Although the amended bill passed the Senate unanimously, the Company is unable to predict if it will pass the House of Representatives and in what form, and if passed by the House, if it will be signed by the Governor. If enacted in its current form, Senate Bill 266 will provide the Company with significant flexibility to pursue its growth strategy, despite the delay in restructuring.

The Company had been in discussions with the PRC staff and other parties in an attempt to arrive at a settlement agreement which addresses the concerns of the parties and allows separation to continue without significant delay. The discussions have not continued pending conclusion of the New Mexico Legislative session in mid March, 2001. However, if Restructuring is not delayed by the Legislature, it is likely the discussions will be revived. The potential outcome of any future discussions may be different from the plan the Company filed on May 31, 2000 and could potentially affect the realizability of certain regulatory assets recorded by the Company (See "Other Issues Facing the Company
- The Restructuring Act and Formation of the Holding Company - Stranded Costs").

In addition to the PRC's approval, completion of corporate separation will require a number of regulatory approvals by, among others, the Securities and Exchange Commission. Approvals from the Federal Energy Regulatory Commission and the Nuclear Regulatory Commission have been obtained. In June 2000, shareholders approved the share exchange; however, completion of corporate separation will also require certain other consents. Completion may also entail significant restructuring activities with respect to the Company's existing liquidity arrangements and the Company's publicly-held senior unsecured notes of which $368 million were outstanding as of December 31, 2000. Under the Proposed Plan, holders of the Company's senior unsecured notes, $100 million at 7.5% and $268.4 million at 7.1%, will be offered the opportunity to exchange their securities for like senior unsecured notes to be issued by the newly created regulated business (see "Liquidity and Capital Resources - Financing Activities and Proposed Holding Company Plan" above).

Stranded Costs

The Restructuring Act recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers ("stranded costs"). Stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see "NRC Prefunding" below).

The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. On May 31, 2000, the Company filed with the PRC its proposal to recover its stranded costs. These costs, excluding nuclear decommissioning costs, total a present value of $691.6 million. In addition, stranded costs associated with decommissioning the Company's portion of the Palo Verde nuclear plant total an additional present value of $44.4 million. This amount considers the effect of expected earnings on the Company's qualified nuclear decommissioning trusts.

Approximately $141 million of costs associated with the unregulated businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these regulatory assets continue to be classified as regulatory assets, although the Company has discontinued Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for the Discontinuance of Application of FASB Statement 71." In 2000, the Company expensed $6.6 million of these assets based on management's view of the probable financial outcome of restructuring in New Mexico upon existing circumstances. If discussions with the PRC staff and other parties result in a settlement in which the amount the Company recovers for stranded costs is less than the amount it has recorded on the balance sheet as regulatory assets, the Company will be required to write-off the difference between its recovery of these costs and the amount it has currently recorded. Likewise, if a delay in corporate separation occurs, the Company may be required to write-off all or a portion of these assets due to the uncertainty of recovery resulting from enactment of the delay. However, Senate Bill 266, as amended, establishes certain regulatory provisions affecting these costs, which if enacted along with the delay, will allow the Company to recover mine reclamation costs (see Note 2 to the Consolidated Financial Statements).

The Company believes that the Restructuring Act if properly applied provides an opportunity for recovery of a reasonable amount of stranded costs. If regulatory orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. Final determination and quantification of stranded cost recovery has not been made by the PRC. The determination will 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 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 through 2007 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company is still evaluating its expected transition costs and has not made a final determination of those costs. The Company, however, currently estimates that these costs will be approximately $46 million, including allowances for certain costs which are non-deductible for income tax purposes. To date, the Company has capitalized $19.1 million of expenditures that meet the Restructuring Act's definition of transition-related costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing system changes and

public and customer education and communications. Recoverable transition costs are currently being capitalized and will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. If the amount of non-recoverable transition costs is material, the resulting charge to earnings may have a material effect on the future financial results and position of the Company.

NRC Prefunding

Pursuant to NRC rules on financial assurance requirements for the decommissioning of nuclear power plants, the Company has a program for funding its share of decommissioning costs for PVNGS through a sinking fund mechanism (see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met.

The Restructuring Act allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs (see "Stranded Costs"). The Restructuring Act 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 states that it is not requiring 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. If the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans.

In addition, as part of the determination and quantification of the stranded costs related to the decommissioning, the Company estimated its future decommissioning costs. If the Company's estimate proves to be less than the actual costs of decommissioning, any cost in excess of the amount allowed through stranded cost recovery may not be recoverable. Such excess costs, if any, will also be subject to the pre-funding requirements discussed above.

Competition

Under current law, the Company is not in direct retail competition with any other regulated electric and gas utility. Nevertheless, the Company is subject to varying degrees of competition in certain territories adjacent to or within areas it serves that are also currently served by other utilities in its region as well as cooperatives, municipalities, electric districts and similar types of government organizations.

As a result of the Restructuring Act, the Company may face competition from companies with greater financial and other resources. There can be no assurance that the Company will not face competition in the future that would adversely affect its results.

It is the current intention to have the Company's unregulated businesses under the Restructuring Act engage primarily in energy-related businesses that will not be regulated by state or Federal agencies that currently regulate public utilities (other than the FERC and NRC). These competitive businesses, including the generation business, will encounter competition and other factors not previously experienced by the Company, and may have different, and perhaps greater, investment risks than those involved in the regulated business that will be engaged in by UtilityCo. Specifically, the passage of the Restructuring Act and deregulation in the electric utility industry generally are likely to have an impact on the price and margins for electric generation and thus, the return on the investment in electric generation assets. In response to competition and the need to gain economies of scale, electricity producers will need to control costs to maintain margins, profitability and cash flow that will be adequate to support investments in new technology and infrastructure. The Company will have to compete directly with independent power producers, many of whom will be larger in scale, thus creating a competitive advantage for those producers due to scale efficiencies.

The New Mexico Legislature is currently considering legislation that could delay open access and other activities under the Restructuring Act, including corporate separation. A delay without providing business flexibility could have a negative effect on the Company's ability to compete in the wholesale power market. Under the current regulatory environment in New Mexico, the Company is unable to achieve the necessary business flexibility it requires to take advantage of business opportunities to execute its growth strategy. There can be no assurance that the Company can successfully compete in the wholesale power marketplace and continue to execute its growth strategy if implementation of the Restructuring Act is rolled back. Senate Bill 266, as originally introduced, simply delayed restructuring for five years. However, during the course of committee hearings and floor debate, the bill was amended so as to provide significant business flexibility to utilities despite the delay. As amended, Senate Bill 266 passed the Senate 39-0 and is now pending in the House of Representatives.

ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS

Under the terms of an agreement and plan of restructuring and merger, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light division and Kansas Gas and Electric subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to and as a condition to, the consummation of this combination, Western Resources will reorganize all of its non-utility assets, including its 85% stake in Protection One and its 45% investment in ONEOK, into Westar Industries which will be spun off to Western Resources' shareholders prior to the acquisition of Western's utility assets by the Company.

The new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries and 39 million shares to the Company's shareholders. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41% will be owned by former Company shareholders and 59% will be owned by former Western Resources shareholders and Westar Industries.

Based on the Company's average closing price over the last ten days prior to the announcement of the transaction of $27.325 per share, the indicated equity consideration of the transaction is approximately $1.5 billion. In addition, approximately $2.9 billion of existing Western Resources debt will be retained, giving the transaction an aggregate enterprise value of approximately $4.4 billion. The new company will undertake to refinance and reduce the debt on Western Resources' books. The new holding company will have a total enterprise value of approximately $6.5 billion ($2.6 billion in equity; $3.9 billion in debt and preferred stock).

The transaction will be accounted for as a reverse acquisition by the Company as the former Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes, Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the operations of the combined company only from the date of acquisition.

In the transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. The portion of each Western Resources share not converted into Westar stock in connection with the spin-off will be exchanged for a fraction of a share of the new holding company in accordance with an exchange ratio to be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the terms of the agreement, Western Resources and Westar Industries have been given an incentive to reduce Western Resources net debt balance prior to the consummation of the transaction. The agreement contains a mechanism to adjust the transaction consideration based on additional equity contributions. Under this mechanism, Western Resources could undertake certain activities not affecting its utility operations to reduce the net debt balance of the utility. The effect of such activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in

the transaction. In addition, Westar Industries has the option of making additional equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $407 million of such equity infusions may be used to purchase additional new holding company common and convertible preferred stock.

At closing, Jeffrey E. Sterba, present chairman, president and chief executive officer of the Company, will become chairman, president and chief executive officer of the new holding company, and David C. Wittig, present chairman, president and chief executive officer of Western Resources, will become chairman, president and chief executive officer of Westar Industries. The Board of Directors of the new company will consist of six current Company board members and three additional directors, two of whom will be selected by the Company from a pool of candidates nominated by Western Resources, and one of whom will be nominated by Westar Industries. The new holding company will be headquartered in New Mexico. Headquarters for the Kansas utilities will remain in Kansas.

The Company expects that the shareholders of the new holding company will receive the Company's dividend. The Company's current annual dividend is $0.80 per share. There can be no assurance however that any funds, property or shares will be legally available to pay dividends at any given time or if available, the new holding company's Board of Directors will declare a dividend.

The companies expect the transaction to be completed within the next 12 to 18 months. The successful spin-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the Kansas Corporation Commission, the New Mexico Public Regulation Commission, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The new holding company expects to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. The Company expects that all of the above mentioned approvals will be obtained; however, such approvals are not assured.

WESTERN UNITED STATES WHOLESALE POWER MARKET

A significant portion of the Company's earnings in 2000 was derived from the Company's wholesale power trading operations which benefited from the strong demand and high wholesale prices in the Western United States. These market conditions were primarily driven by the electric power supply shortages in the Western United States. As a result of the supply imbalance, the wholesale power market in the Western United States has become extremely volatile and, while providing many marketing opportunities, presents significant risk to companies selling power into this marketplace.

During 2000, regional wholesale electricity prices reached over $1,000 per MWh mainly due to the electric power shortages in the West. Two of California's major utilities, SCE and PG&E, were unable to pass this cost on to their ratepayers. As a result, both utilities are experiencing severe liquidity constraints and have each stated publicly that they may file for bankruptcy. In

response to the financial difficulties being experienced by SCE and PG&E and the resulting turmoil in the California market, the U.S. Secretary of Energy imposed a "soft" price cap of $150 per MWh effective January 1, 2001, and expiring January 23, 2001. This price cap was subsequently extended to February 7, 2001. The price cap requires that any wholesale sales of electricity into the California market be capped at $150 MWh unless the seller can demonstrate that its costs exceed the cap. In addition, the Governor and legislature of California are considering a number of proposals which may put downward pressure on the price of electricity including, but not limited to, a restructured power auction system and the purchase of power by the state on a long-term basis. It is unclear what effect these measures will have on the price of electricity in California and the surrounding states. Such measures may have an impact on the sustainability of the high electric power prices experienced in 2000.

The Company is not a major participant in the California market. In 2000, approximately seven percent of all wholesale power sales by the Company were made directly to the California Power Exchange ("California PX"), which was the main market for the purchase and sale of electricity in the state during 2000 and the beginning of 2001, or the California Independent System Operator ("California ISO"), which manages the state's electricity transmission network. At December 31, 2000, amounts due from the California PX or ISO for power sold to them totaled $10.5 million. In January and February 2001, SCE and PG&E, major purchasers of power from the California PX and ISO, defaulted on payments due the California PX for power purchased from the PX in 2000. In addition, these companies defaulted on various debt obligations in January and February 2001 due third party creditors. The impact of these defaults on the Company was immaterial.

However, under the terms of the participation agreement with the California PX, defaults by the PX's debtors are charged-back proportionally to the creditors based on their level of participation in the exchange in the three months preceding the respective default. Through February 8, 2001, the PX has had defaults of $865 million by SCE and PG&E for power purchased in November 2000. Additional defaults may occur. The Company has been invoiced for $2.3 million as its proportionate share under the participation agreement. A number of power marketers and generators have filed a complaint with the FERC to halt the PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application is unreasonable and destabilizing to the California power market. If the FERC does not intercede, and the participating creditors do not make payments, the PX may draw upon letters of credit and other collateral on deposit with the exchange. The Company has issued the PX a letter of credit of $3 million. The Company does not believe the charge-back is appropriate and is evaluating its course of action; however, the Company does not believe the situation will have a material adverse effect on its results of operations or financial condition.

In addition to sales to the California PX and ISO, the Company sells power to customers in other jurisdictions who sell to the California PX and ISO and whose ability to pay may be dependent on payment from California. The Company is unable to determine whether its non-California power sales ultimately are resold in the California market. The Company's credit risk is monitored by its Risk Management Committee, which is comprised of senior finance and operations managers. The Company seeks to minimize its exposure through established credit limits, a diversified customer base and the structuring of transactions to take advantage of off-setting positions with its customers. To the extent these customers who sell power into California are dependent on payment from California to make their payments to the Company, the Company may be exposed to credit risk which did not exist prior to the California situation.

In 2000, in response to the increased credit risk and market price volatility described above, the Company recognized $8.5 million of losses to reflect management's estimate of the increased risk in the wholesale power market and its impact on 2000 revenues. This determination was based on a methodology that considers the credit ratings of its customers and the price volatility in the marketplace, among other things. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly.

The California Public Utilities Commission ("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 not heard further from the CPUC. 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 near future in connection with this investigation. However, no such subpoena has yet been forthcoming.

In addition, there are several class action lawsuits that have been filed in California against generators and wholesale sellers of energy into the California market. These actions allege, in essence, that the defendants engaged in unlawful and unfair business practices to manipulate the wholesale energy market, fix prices and restrain supply, and thereby drive up prices. The Company is not a named defendant in any of these actions, and there has been no claim or threat of litigation against the Company arising out of the matters addressed in 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 discussed above, SCE has defaulted on certain of its obligations and has publicly announced that it may declare bankruptcy. SCE is a 15.8% participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an agreement among the participants in PVNGS and an agreement among the participants in Four Corners Units 4 and 5, each participant is required to fund its proportionate share of operation and maintenance, capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly share of these costs to be approximately $7.1 million for PVNGS and $8.0 million for Four Corners. The agreements provide that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant for a period of six months. During this time the defaulting participant is entitled to its share of the power generated by the respective station. After this grace period, the defaulting participant must make its payments in arrears before it is entitled to its continuing share of power. As of February 1, 2001, SCE has not defaulted on its payment obligations with respect to PVNGS and Four Corners. The Company is unable to predict whether the California situation will cause SCE to default on its payment obligations.

Implementation of New 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.

Under PRC rules and PRC approved Company rules, the Company is required to issue customer bills on a monthly basis. The Company was granted a temporary variance, and the PRC began a hearing on whether the Company violated PRC rules, regulations or orders or the New Mexico Public Utility Act. The investigation was concluded on November 2, 1999, without the PRC imposing any civil penalty on the Company and with an approved stipulation that the Company be permitted to bill an additional service charge to customers who were not billed the appropriate electric service charge or gas access fee. The stipulation was limited to approximately $0.7 million in the November and December billing cycles.

Because of the implementation issues associated with the new billing system, the Company estimated retail gas and electric revenues through July 1999. Beginning with August 1999, the Company was able to determine actual revenues for all prior periods affected and began reconciling with previously estimated revenues. In December 1999, the Company completed its reconciliation of system revenues. As a result, 1999 revenues represented actual revenues as determined by the new billing system. The resulting reconciliation did not materially impact recorded revenues. However, a significant number of individual accounts required corrections.

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 estimate of bad debt costs throughout 1999.

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. As a result, the Company has determined that $13.5 million of customer receivables will not be collectible. Based upon information available at December 31, 2000, the Company believes the allowance for doubtful accounts of $9.0 million is adequate for management's estimate of potential uncollectible accounts.

In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $2 million in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than in the past years.

The following is a summary of the allowance for doubtful accounts during 2000, 1999 and 1998:

                                                    2000      1999     1998
                                                  --------  --------  -------
                                                            (In thousands)
Allowance for doubtful accounts, beginning
  of year.......................................  $ 12,504  $    836  $   783
Bad debt expense................................     9,980    11,496    3,325
Less:  Write off (adjustments) of uncollectible
       accounts.................................    13,521      (172)   3,272
                                                  --------  --------- -------
Allowance for doubtful accounts, end of year ...  $  8,963  $ 12,504  $   836
                                                  ========  ========= =======

Electric Rate Case

In November 1998, the NMPUC issued a final order in the Company's electric rate case, requiring the Company to reduce rates in 1999 by $60.2 million, by $25.6 million in 2000 and by an additional $25.6 million in 2001. The rate reduction order reflected, among other things, the revaluation of the Company's generation resources based on a so-called "market-based price" and the finding by the NMPUC that recovery of stranded costs is illegal. In December 1998, the Company appealed the rate case order to the New Mexico Supreme Court ("Supreme Court").

On March 15, 1999, the Supreme Court issued a ruling, vacating the NMPUC order on the Company's electric rate case and remanding the case to the PRC, the successor of the NMPUC, for further proceedings.

On August 25, 1999, the PRC issued an order approving a settlement. The PRC ordered the Company to reduce its electric rates by $34.0 million retroactive to July 30, 1999. In addition, the order includes a rate freeze until retail electric competition is fully implemented in New Mexico or until January 1, 2003 whichever is earlier. The settlement reduces electric distribution operating revenues by approximately $39 million and $19 million in 2000 and 1999, respectively.

GAS RATE ORDERS

In April 2000, the Supreme Court ruled in favor of the Company in overturning a $6.9 million rate reduction imposed on the Company's natural gas utility by the state's former NMPUC in 1997 for its 1995 gas rate case. Although the Supreme Court upheld certain portions of the gas rate case order by the PUC, the Supreme Court vacated the rate order as "unreasonable and unlawful" because certain disallowances ordered by the PUC unreasonably hindered the Company's ability to earn a fair rate of return. The case was remanded to the PRC. In addition in March 2000, the Supreme Court vacated the PUC's final order in the Company's 1997 gas rate case and remanded it back to the PRC. The Supreme Court specifically rejected portions of the final order requiring the Company to offer residential customers a choice of utility access fees.

Rate Case Settlement

On October 24, 2000, the PRC issued a final order approving a stipulation negotiated in the third quarter between the Company and the PRC staff which resolved all issues raised by the two remanded rate cases. The final order adds approximately $1.2 million to the Company's revenues in the final quarter of 2000, $4.7 million in 2001, and $3.9 million in 2002. The Company has reversed certain reserves against costs recovered in the settlement that were recorded against earnings at the time of the original regulatory orders, resulting in a one-time pre-tax gain of $4.6 million. This amount will be collected from customers in rates over the next 12 years.

NUCLEAR DECOMMISSIONING TRUST

In 1998, the Company and the trustee of the Company's master decommissioning trust filed a civil complaint and an amended complaint, respectively, against several companies and individuals for the under-performance of a corporate owned life insurance program. The program was used to fund a portion of the Company's nuclear decommissioning obligations for its 10.2% interest in PVNGS.

The parties reached a settlement agreement under which the complaint and counterclaim were dismissed with prejudice on September 5, 2000 and the Company and trustee received $13.8 million in settlement proceeds.

Effects of Certain Events on Future Revenues

The Company's 100 MW power sale contract with San Diego Gas and Electric Company ("SDG&E") will expire in April of 2001. SDG&E has verbally notified the Company that it will not renew this contract. The FERC must ultimately approve the termination of the contract. The Company currently estimates that the net revenue reduction resulting from the expiration of the SDG&E contract will be approximately $20 million annually. Whether or not these revenues will be replaced depends on market conditions. In addition, previously reported litigation between the Company and SDG&E regarding prior years' contract pricing has been resolved in the Company's favor.

On October 4, 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 Western under the Company's Open Access Transmission Tariff on behalf of the United States Department of Energy ("DOE") as contracting agent for KAFB. The Company is opposing the WAPA petition and intends to litigate this matter vigorously. The net revenue reduction to the Company if the DOE replaces the Company as the power supplier to KAFB is estimated to be approximately $7.0 million annually. Whether or not these revenues will be replaced depends on market conditions.

As part of the rate case settlement (discussed above), the Company agreed that certain changes to the language of the retail tariff under which Kirtland Air Force Base ("KAFB") currently takes service would be considered in a separate proceeding before the PRC. Hearings on this issue have not yet been scheduled. The PRC is considering briefs submitted by the parties addressing the scope of the proceeding. KAFB has not renewed its electric service contract with the Company that expired in December 1999 but continues to purchase retail service from the Company. (See Item 3. - "Legal Proceedings - Other Proceedings
- Kirtland Air Force Base ("KAFB") Contract").

COAL FUEL SUPPLY

In 1997, the Company was notified by SJCC, supplier of coal to SJGS, of certain audit exceptions identified by the Federal Minerals Management Service ("MMS") for the period 1986 through 1997. These exceptions pertain to the valuation of coal for purposes of calculating the Federal coal royalty. Primary issues include whether coal processing and transportation costs should be included in the base value of La Plata coal for royalty determination. The Company was notified during the fourth quarter of 2000 that SJCC and the MMS agreed to a settlement of all claims. The Company's share of the settlement including a recalculation of current invoices was approximately $3 million. The Company recorded the settlement as part of its cost of coal in the fourth quarter of 2000.

In 1996, the Company was notified by SJCC that the Navajo Nation proposed to select certain properties within the San Juan and La Plata Mines (the "mining properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the "Act"). The mining properties are operated by SJCC under leases from the BLM and comprise a portion of the fuel supply for the SJGS. An administrative appeal by SJCC is pending. In the appeal, SJCC argued that transfer of the mining properties to the Navajo Nation may subject the mining operations to taxation and additional regulation by the Navajo Nation, both of which could increase the price of coal that might potentially be passed on to the SJGS through the existing coal sales agreement. The Company is monitoring the appeal and other developments on this issue and will continue to assess potential impacts to the SJGS and the Company's operations. The Company is unable to predict the ultimate outcome of this matter.

FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY

The Company's generation mix for 2000 was 68.0% coal, 39.8% nuclear and 2.2% gas and oil. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits and the generally abundant supply of nuclear fuel, the Company believes that adequate sources of fuel are available for its generating stations (see "COAL FUEL SUPPLY" above).

Water for Four Corners and SJGS is obtained from the San Juan River. BHP holds rights to San Juan River water and has committed a portion of those rights to Four Corners through the life of the project. The Company and Tucson have a contract with the USBR for consumption of 16,200 acre feet of water per year for the SJGS. The contract expires in 2005. In addition, the Company was granted the authority to consume 8,000 acre feet of water per year under a state permit that is held by BHP. The Company is of the opinion that sufficient water is under contract for the SJGS through 2005. The Company has signed a contract with the Jicarilla Apache Tribe for a twenty-seven year term, beginning in 2006, for replacement of the current USBR contract for 16,200 acre feet of water. The contract must still be approved by the USBR and is also subject to environmental approvals. The Company is actively involved in the San Juan River Recovery Implementation Program to mitigate any concerns with the taking of the negotiated water supply from a river that contains endangered species and critical habitat. The Company believes that it will continue to have adequate sources of water available for its generating stations.

The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company's peak-day demand. The Company serves certain cities which depend on EPNG or Transwestern Pipeline Company for transportation of gas supplies. Because these cities are not directly connected to the Company's transmission facilities, gas transported by these companies is the sole supply source for those cities. The Company believes that adequate sources of gas are available for its distribution systems.

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 and is in the process of attempting to negotiate settlement agreements with one of those other companies. No complaint has been filed against the Company, and the Company believes that all of the routine maintenance, repair, and replacement work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New Mexico Environment Department ("NMED") made an information request of the Company, advising the Company that the NMED was in the process of assisting the EPA in the EPA's nationwide effort "of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's Prevention of Significant Determination ("PSD") policies." The Company has responded to the NMED information request.

The nature and cost of the impacts of EPA's changed interpretation of the application of the NSR and NSPS, together with proposed changes to these regulations, may be significant to the power production industry. However, the Company cannot quantify these impacts with regard to its power plants. It is also unknown what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. 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 affect on the Company's financial position and results of operations.

COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS

The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes.

The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts).

The Company's recorded estimated minimum liability to remediate its identified sites is $8.3 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $21.1 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company.

Labor Union Negotiations

The collective bargaining agreement between the Company and the International Brotherhood of Electrical Workers Local Union 611 ("IBEW"), which covers the approximately 654 bargaining unit employees in the Utility and Generation and Trading Operations expired on May 1, 2000, but continued in full force and effect while the parties negotiated. The successor agreement was reached on August 22, 2000 and was ratified by IBEW members on September 1, 2000. The IBEW's charge with the National Labor Relations Board ("NLRB") alleging the Company has bargained in bad faith, and by its actions has committed an unfair labor practice is pending. The Company will vigorously defend against the Union's allegations.

NAVAJO NATION TAX ISSUES

APS, the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues.

NEW AND PROPOSED ACCOUNTING STANDARDS

Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has questioned certain of the current accounting practices of the electric industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In February 2000, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding Accounting for Obligations Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft requires the recognition of a liability for an asset retirement obligation at fair value. In addition, present value techniques used to calculate the liability must use a credit adjusted risk-free rate. Subsequent remeasures of the liability would be recognized using an allocation approach. The Company has not yet determined the impact of the Exposure Draft.

Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"): SFAS 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting 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. In June 1999, FASB issued SFAS 137 to amend the effective date for the compliance of SFAS 133 to January 1, 2001. In June 2000, the FASB issued SFAS 138 that provides certain amendments to SFAS 133. The amendments, among other things, expand the normal sales and purchases exception to contracts that implicitly or explicitly permit net settlement and contracts that have a market mechanism to facilitate net settlement. The expanded exception excludes a significant portion of the Company's contracts that previously would have required valuation under SFAS 133. Effective January 1, 2001, the Company adopted SFAS 133, as amended.

The Company has identified all financial instruments that meet the definition of a derivative under SFAS 133, as amended, as of January 1, 2001 in which the Company is a party. Certain of the Company's identified derivative instruments are marked-to-market under EITF 98-10 as of December 31, 2000. The related gains and losses (unrealized and realized) for these derivative instruments are recorded as adjustments to operating revenues. In addition, the financial instruments underlying the Company's corporate hedge of certain investments in its nuclear, executive retirement and retiree medical benefits trusts meet the definition of a derivative under SFAS 133, as amended, and are marked-to-market as of December 31, 2000. The related unrealized and realized losses are recorded as a component of other income and deductions on the Consolidated Statement of Earnings.

Pursuant to SFAS 133, as amended, the Company designated certain forward purchase contracts for electricity as cash flow hedges. The Company's designated cash flow hedges at January 1, 2001, were forward purchase contracts for the purchase of electric power for forecasted jurisdictional use during planned outages in 2001. The hedged risks associated with these instruments are the changes in cash flows associated with the forecasted purchase of electricity due to changes in the price of electricity on the spot market. Assessment of hedge effectiveness will be based on the changes in the forward price of electricity.

SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings.

Because the Company's derivative instruments as defined by SFAS 133, as amended, are currently marked-to-market or are classified as cash flow hedges, the adoption of SFAS 133, as amended, will not have an impact on the net earnings of the Company. However, the adoption of SFAS 133, as amended, will increase comprehensive income by $6.0 million, net of taxes for the recording of the Company's cash flow hedges. The physical contracts will subsequently be recognized as a component of the cost of purchased power when the actual physical delivery occurs. At January 1, 2001, the derivative instruments designated as cash flow hedges had a gross asset position of $9.9 million on the hedged transactions. See Note 5 for financial instruments currently marked-to-market.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of the Company are based upon current expectations and are subject to risk and uncertainties, as are the forward-looking statements with respect to the benefits of the Company's proposed acquisition of Western Resources and the businesses of the Company and Western Resources. 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 supply and demand in the market for electric power, the performance of generating units and the transmission system, and state and federal regulatory and legislative decisions and actions, including rulings issued by the NMPRC pursuant to the Electric Utility Industry Restructuring Act of 1999 and in other cases now pending or which may be brought before the commission and any action by the New Mexico Legislature to amend or repeal that Act, or other actions relating to restructuring or stranded cost recovery, or federal or state regulatory, legislative or legal action connected with the California wholesale power market, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing.

In addition, factors that could cause actual results or outcomes related to the proposed acquisition of Western Resources to differ materially from those indicated by such forward looking statements include, but are not limited to, risks and uncertainties relating to: the possibility that shareholders of the Company and/or Western Resources will not approve the transaction, the risks that the businesses will not be integrated successfully, the risk that the benefits of the transaction may not be fully realized or may take longer to realize than expected, disruption from the

transaction making it more difficult to maintain relationships with clients, employees, suppliers or other third parties, conditions in the financial markets relevant to the proposed transaction, the receipt of regulatory and other approvals of the transaction, that future circumstances could cause business decisions or accounting treatment to be decided differently than now intended, changes in laws or regulations, changing governmental policies and regulatory actions with respect to allowed rates of return on equity and equity ratio limits, industry and rate structure, stranded cost recovery, operation of nuclear power facilities, acquisition, disposal, depreciation and amortization of assets and facilities, operation and construction of plant facilities, recovery of fuel and purchased power costs, decommissioning costs, present or prospective wholesale and retail competition (including retail wheeling and transmission costs), political and economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions (including natural disasters such as tornadoes), population growth rates and demographic patterns, competition for retail and wholesale customers, availability, pricing and transportation of fuel and other energy commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation or in accounting standards, unanticipated delays or changes in costs for capital projects, unanticipated changes in operating expenses and capital expenditures, capital market conditions, competition for new energy development opportunities and legal and administrative proceedings (whether civil, such as environmental, or criminal) and settlements, the outcome of Protection One accounting issues reviewed by the SEC staff as disclosed in previous Western Resources SEC filings, and the impact of Protection One's financial condition on Western Resources' consolidated results.