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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

x ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2004

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     

 

Commission File Number 1-3523

 

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Kansas


 

48-0290150


(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification Number)

818 South Kansas Avenue, Topeka, Kansas 66612


 

(785) 575-6300


(Address, including Zip code and telephone number, including area code, of registrant’s principal executive offices)

 


 

Securities registered pursuant to section 12(b) of the Act:

 

Common Stock, par value $5.00 per share


  

New York Stock Exchange


(Title of each class)    (Name of each exchange on which registered)

 

Securities registered pursuant to section 12(g) of the Act:

 

Preferred Stock, 4-1/2% Series, $100 par value

(Title of Class)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x     No ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x     No ¨

 

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $1,706,425,434 at June 30, 2004.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

 

Common Stock, par value $5.00 per share


  

86,400,384 shares


(Class)    (Outstanding at March 1, 2005)

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Description of the document


  

Part of the Form 10-K


Portions of the Westar Energy, Inc. definitive proxy statement to be used in connection with the registrant’s 2005 Annual Meeting of Shareholders   

Part III (Item 10 through Item 14)

(Portions of Item 10 are not incorporated

by reference and are provided herein)

 



Table of Contents

 

TABLE OF CONTENTS

 

          Page

     PART I     

Item 1.

  

Business

   4

Item 2.

  

Properties

   19

Item 3.

  

Legal Proceedings

   20

Item 4.

  

Submission of Matters to a Vote of Security Holders

   20
     PART II     

Item 5.

  

Market for Registrant’s Common Equity and Related Stockholder Matters

   20

Item 6.

  

Selected Financial Data

   21

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   22

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   37

Item 8.

  

Financial Statements and Supplementary Data

   40

Item 9.

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

   93

Item 9A.

  

Controls and Procedures

   93

Item 9B.

  

Other Information

   93
     PART III     

Item 10.

  

Directors and Executive Officers of the Registrant

   93

Item 11.

  

Executive Compensation

   93

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management

   94

Item 13.

  

Certain Relationships and Related Transactions

   94

Item 14.

  

Principal Accountant Fees and Services

   94
     PART IV     

Item 15.

  

Exhibits and Financial Statement Schedules

   94

Signatures

   100

 

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FORWARD-LOOKING STATEMENTS

 

Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning:

 

    capital expenditures,

 

    earnings,

 

    liquidity and capital resources,

 

    litigation,

 

    accounting matters,

 

    possible corporate restructurings, acquisitions and dispositions,

 

    compliance with debt and other restrictive covenants,

 

    interest rates and dividends,

 

    environmental matters,

 

    nuclear operations, and

 

    the overall economy of our service area.

 

What happens in each case could vary materially from what we expect because of such things as:

 

    electric utility deregulation or re-regulation,

 

    regulated and competitive markets,

 

    ongoing municipal, state and federal activities,

 

    economic and capital market conditions,

 

    changes in accounting requirements and other accounting matters,

 

    changing weather,

 

    rates, cost recoveries and other regulatory matters,

 

    the impact of changes and downturns in the energy industry and the market for trading wholesale electricity,

 

    the outcome of the notice of violation received on January 22, 2004 from the Environmental Protection Agency and other environmental matters,

 

    political, legislative, judicial and regulatory developments,

 

    the impact of the purported shareholder and employee class action lawsuits filed against us,

 

    the impact of our potential liability to David C. Wittig and Douglas T. Lake for unpaid compensation and benefits and the impact of claims they have made against us related to the termination of their employment and the publication of the report of the special committee of the board of directors,

 

    the impact of changes in interest rates,

 

    changes in, and the discount rate assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan assets,

 

    the impact of changing interest rates and other assumptions on our nuclear decommissioning liability for Wolf Creek Generating Station,

 

    Kansas Corporation Commission and the North American Electric Reliability Council’s utility service reliability standards,

 

    homeland security considerations,

 

    coal, natural gas, oil and wholesale electricity prices,

 

    availability and timely provision of rail transportation for our coal supply, and

 

    other circumstances affecting anticipated operations, sales and costs.

 

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

 

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PART I

 

ITEM 1. BUSINESS

 

GENERAL

 

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

 

We provide electric generation, transmission and distribution services to approximately 653,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

 

KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas, and a 47% interest in Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek.

 

SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2004

 

Common Stock Issuance

 

Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million.

 

Reduction of Debt

 

During 2004, we reduced our total debt balance by $533.4 million, from $2.2 billion at December 31, 2003 to $1.7 billion at December 31, 2004.

 

Discontinued Operations — Sale of Protection One

 

On February 17, 2004, we closed the sale of our interest in Protection One, Inc. (Protection One) to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). On November 12, 2004, we settled issues remaining after the sale by entering into a settlement agreement with Protection One and Quadrangle that, among other things, terminated a tax sharing agreement, settled Protection One’s claims with us related to the tax sharing agreement and settled claims between Quadrangle and us related to the sale transaction. Our net cash payment under the settlement agreement was $13.4 million. We recorded after tax income from discontinued operations of $78.8 million in 2004 and after tax loss from discontinued operations of $77.9 million in 2003.

 

OPERATIONS

 

General

 

Westar Energy supplies electric energy at retail to approximately 352,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 301,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 54 cities in Kansas and four electric cooperatives that serve rural areas of Kansas. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we engage in energy marketing and purchase and sell wholesale electricity in areas outside our historical retail service territory.

 

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Generation Capacity

 

We have 5,844 megawatts (MW) of generating capacity, of which 2,587 MW is owned or leased by KGE. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.

 

Fuel Type


   Capacity
(MW)


   Percent of
Total Capacity


Coal

   3,292.0    56.3

Nuclear

   548.0    9.4

Natural gas or oil

   1,920.0    32.9

Diesel fuel

   83.0    1.4

Wind

   1.2    —  
    
  

Total

   5,844.2    100.0
    
  

 

Our aggregate 2004 peak system net load of 4,455 MW occurred on August 3, 2004. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 20% above system peak responsibility at the time of our 2004 peak system net load.

 

We have agreed to provide generating capacity to other utilities as set forth below.

 

Utility


   Capacity (MW)

  Period Ending

Midwest Energy, Inc.

   20   May 2005

Midwest Energy, Inc.

   130   May 2008

Midwest Energy, Inc.

   125   May 2010

Empire District Electric Company

   162   May 2010

Oklahoma Municipal Power Authority

   60   December 2013

McPherson Board of Public Utilities (McPherson)

   (a)   May 2027
 
  (a) We provide base load capacity to McPherson. McPherson provides peaking capacity to us. During 2004, we provided approximately 77 MW to, and received approximately 178 MW from, McPherson. The amount of base load capacity provided to McPherson is based on a fixed percentage of McPherson’s annual peak system load.  

 

Fossil Fuel Generation

 

Fuel Mix

 

The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the lesser quantity of the fuel it takes to produce electricity. The quantity of heat consumed during the generation of electricity is measured in millions of Btu (MMBtu).

 

Based on MMBtus, our 2004 actual fuel mix was 79% coal, 16% nuclear and 5% natural gas, oil or diesel fuel. We expect in 2005 to use a higher percentage of coal and a lower percentage of uranium because in 2005 we will refuel Wolf Creek. Our fuel mix fluctuates with the operation of Wolf Creek, as discussed below under “— Nuclear Generation,” fluctuations in fuel costs, plant availability, customer demand and the cost and availability of wholesale market power.

 

Coal

 

Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center have an aggregate capacity of 2,213 MW, of which we own an 84% share, or 1,859 MW. We have a long-term coal supply contract with Foundation Coal West to supply coal to Jeffrey Energy Center from mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu delivery quantities. All of the coal used at Jeffrey Energy Center is purchased under this contract. The contract expires December 31, 2020. The contract provides for price escalation, based on certain indexed costs of production. The price for quantities

 

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purchased over the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects then current market prices. The next re-pricing is scheduled for 2008.

 

The coal supplied to Jeffrey Energy Center during 2004 was surface mined and had an average Btu content of approximately 8,449 Btu per pound and an average sulfur content of 0.47 lbs/MMBtu (see “— Environmental Matters” for a discussion of sulfur content). The average delivered cost of coal burned at Jeffrey Energy Center during 2004 was approximately $1.24 per MMBtu, or $20.93 per ton.

 

We transport coal from Wyoming under a long-term rail transportation contract with the Burlington Northern Santa Fe (BNSF) and Union Pacific railroads. The contract term continues through December 31, 2013. The contract price is subject to price escalation based on certain costs incurred by the rail carriers. We anticipate that the cost of transporting coal may increase due to higher prices for the items subject to contractual escalation.

 

LaCygne Generating Station: The two coal-fired units at LaCygne Generating Station (LaCygne) have an aggregate generating capacity of 1,362 MW, of which we own or lease a 50% share, or 681 MW. LaCygne 1 uses a blended fuel mix containing approximately 85% PRB coal and 15% Kansas/Missouri coal. LaCygne 2 uses PRB coal. The operator of LaCygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for LaCygne. All of the LaCygne 1 and LaCygne 2 PRB coal is supplied through fixed price contracts through 2005 and is transported under KCPL’s Omnibus Rail Transportation Agreement with the BNSF and Kansas City Southern Railroad through December 31, 2010. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers.

 

The PRB coal supplied to LaCygne 1 and LaCygne 2 during 2004 had an average Btu content of approximately 8,630 Btu per pound and an average sulfur content of 0.32 lbs/MMBtu. During 2004, the average delivered cost of all coal burned at LaCygne 1 was approximately $0.89 per MMBtu, or $15.51 per ton. The average delivered cost of coal burned at LaCygne 2 was approximately $0.81 per MMBtu, or $13.74 per ton.

 

Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 752 MW. During 2004, we purchased coal under a contract with Kennecott Coal Sales Company that expired in December 2004. During the first quarter of 2004, we entered into an agreement with Arch Coal, Inc. for coal to be supplied to these energy centers beginning in 2005 and extending through 2009. This contract is expected to provide 100% of the coal requirement for these energy centers through 2007 and 70% of the coal requirements during 2008 and 2009. Approximately 30% of the coal to be delivered under this contract is priced within a specified range of spot market prices for 2005 through 2007 and approximately 43% of the coal to be delivered under this contract is priced within a specified range of spot market prices in 2008 and 2009.

 

In 2004, the coal supplied to Lawrence and Tecumseh Energy Centers had an average Btu content of approximately 8,905 Btu per pound and an average sulfur content of 0.36 lbs/MMBtu. During 2004, the average delivered cost of all coal burned in the Lawrence units was approximately $1.05 per MMBtu, or $18.58 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.05 per MMBtu, or $18.65 per ton.

 

We transport coal from Wyoming using the BNSF railroad under a contract ending in December 2006. We anticipate entering into a similar contract when the current contract expires. We anticipate that the cost of transporting coal may increase due to higher prices for the items subject to contractual escalation.

 

General: We have entered into all of our coal supply agreements in the ordinary course of business and believe we are not substantially dependent on these contracts. We believe there are other suppliers with plentiful sources of coal available at spot market prices to replace, if necessary, fuel supplied pursuant to these contracts and that we would be able to make transportation arrangements for such coal. In the event that we were required to replace our coal agreements, we would not anticipate a substantial disruption of our business, although the cost of purchasing coal could increase. Because we meet the majority of our coal needs through long-term contracts as discussed above, we do not anticipate being materially impacted by price changes in the spot market.

 

We have entered into all of our coal transportation contracts in the ordinary course of business. Although several rail carriers are capable of serving the coal mines from where our coal originates, several of our generating

 

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stations can be served by only one rail carrier. In the event the rail carrier to one of our generating stations fails to provide reliable service, we could experience a disruption of our business that could have a material adverse impact on our business, consolidated financial condition and results of operations.

 

Natural Gas

 

We use natural gas either as a primary fuel or as a start-up and/or secondary fuel, depending on market prices, at our Gordon Evans, Murray Gill, Neosho, Abilene and Hutchinson Energy Centers, in the gas turbine units at our Tecumseh generating station and in the combined cycle units at the State Line facility. We also use natural gas as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. We purchase natural gas in the spot market, which supplies our facilities with a flexible natural gas supply as necessary to meet operational needs. During 2004, we purchased 4.2 million MMBtu of natural gas on the spot market for a total cost of $28.1 million. Natural gas accounted for approximately 1% of our total fuel burned during 2004.

 

If natural gas prices are higher than the amount we are able to recover through our retail rates, we may be exposed to increased natural gas costs and our exposure could be material. We may be able to reduce our exposure to the risk of high natural gas prices due to our ability to use other fuel types and by using other pricing techniques available to us, such as purchasing derivative contracts. To recover increased natural gas costs in excess of the cost included in retail rates, we would have to file a request for a change in rates with the Kansas Corporation Commission (KCC) or request a recovery mechanism through the KCC, which could be denied in whole or in part. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

 

We maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. (ONEOK). This contract expires April 30, 2006. We expect to renew or renegotiate a new contract to provide this natural gas transportation prior to the current contract expiration. We meet a portion of our natural gas transportation requirements for the Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. We meet all of the natural gas transportation requirements for the State Line facility through a firm natural gas transportation agreement with Southern Star Central Pipeline. The firm transportation agreements that serve the Gordon Evans, Murray Gill, Lawrence and Tecumseh Energy Centers extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016.

 

Oil

 

Once started with natural gas, most of the steam units at our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn oil or natural gas. We use oil as an alternate fuel when economical or when interruptions to natural gas supply make it necessary. During 2004 oil was more economical than natural gas, therefore, we used oil as the primary fuel in these generating facilities for most of 2004. During 2004, we burned 10.3 million MMBtu of oil at a total cost of $38.9 million. Oil accounted for approximately 4% of our total MMBtu of fuel burned during 2004. Because oil does not burn as cleanly as natural gas, our ability to use as much oil in the future could be constrained by new environmental rules or future settlements regarding environmental matters.

 

Oil is also used as a start-up fuel at some of our generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase oil in the spot market and under longer-term contracts. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power, to satisfy emergency requirements and to protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to burn.

 

If oil prices are higher than the amount we are able to recover through our retail rates, we may be exposed to increased oil costs and our exposure could be material. We may be able to reduce our exposure to the risk of high oil prices due to our ability to use other fuel types and by using other pricing techniques available to us, such as purchasing derivative contracts. To recover increased oil costs in excess of the cost included in retail rates, we would have to file a request for a change in rates with the KCC or request a recovery mechanism through the KCC, which could be denied in whole or in part. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

 

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Other Fuel Matters

 

The table below provides information relating to the weighted average cost of fuel that we have used, including the fuel and transportation costs and any other associated costs.

 

     2004

   2003

   2002

Per Million Btu:

                    

Nuclear

   $ 0.39    $ 0.39    $ 0.40

Coal

     1.11      1.07      1.05

Natural gas

     6.62      4.83      3.62

Oil

     3.77      3.24      2.58

Per MWh Generation

   $ 12.64    $ 12.08    $ 11.80

 

Purchased Power

 

At times, we purchase power to meet the energy needs of our customers. Factors that cause us to purchase power to serve our customers include outages at our generating plants, prices for wholesale energy, extreme weather conditions, growth, and other factors. If we were unable to generate an adequate supply of electricity to serve our customers, we would typically purchase power in the wholesale market. Constraints in the transmission system may keep us from purchasing power in which case we would have to implement curtailment or interruption procedures as permitted by our tariffs and terms and conditions of service. Purchased power for the year ended December 31, 2004 comprised approximately 6% of our total operating expenses.

 

Energy Marketing Activities

 

We engage in both financial and physical trading to manage our energy price risks. We trade electricity, coal, natural gas and oil. We use a variety of financial instruments, including forward contracts, options and swaps and we trade energy commodity contracts daily. We also use economic hedging techniques to manage fuel expenditures.

 

Nuclear Generation

 

General

 

Wolf Creek is a 1,166 MW nuclear power plant located near Burlington, Kansas. Wolf Creek began operation in 1985. KGE owns a 47% interest in Wolf Creek, or 548 MW, which represents approximately 9% of our total generating capacity. KCPL owns a 47% interest in Wolf Creek and a 6% interest is owned by Kansas Electric Power Cooperative, Inc. Wolf Creek is operated by WCNOC, a corporation owned by the co-owners of Wolf Creek. The co-owners pay the operating costs of WCNOC equal to their percentage ownership in Wolf Creek. WCNOC has approximately 1,000 employees.

 

Fuel Supply

 

We have 100% of the uranium and conversion services needed to operate Wolf Creek under contract through September 2009. We also have 100% of the enrichment services required to operate Wolf Creek under contract through approximately March 2008. Fabrication requirements are under contract through 2024. We will be exposed to the price risk associated with any components not currently under contract if a counterparty were to fail its contractual obligations.

 

All uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered into in the ordinary course of business, and WCNOC believes Wolf Creek is not substantially dependent on these agreements. However, contraction and consolidation among suppliers of these commodities and services, coupled with increasing worldwide demand and past inventory draw-downs, have introduced uncertainty as to WCNOC’s ability to replace, if necessary, some of these contracts in the event of a protracted supply disruption. WCNOC believes this potential problem is common in the nuclear industry.

 

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Accordingly, in the event the affected contracts were required to be replaced, WCNOC believes that the industry and government would arrive at a solution to minimize disruption of the nuclear industry’s operations.

 

Nuclear fuel is amortized to fuel and purchased power based on the quantity of heat produced for the generation of electricity.

 

Radioactive Waste Disposal

 

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee for the future disposal of spent nuclear fuel. The fee is one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. We include these disposal costs in operating expenses.

 

A permanent disposal site will not be available for the nuclear industry until 2012 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2018. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

 

In 2002, the Yucca Mountain site in Nevada was approved for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. This action allows the DOE to apply to the Nuclear Regulatory Commission (NRC) to license the project. The DOE expects that this facility will open in 2012. However, the opening of the Yucca Mountain site has been delayed many times and could be delayed further due to litigation and other issues related to the site as a permanent repository for spent nuclear fuel.

 

Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on-site facility. WCNOC believes that a temporary loss of low-level radioactive waste disposal capability would not affect Wolf Creek’s continued operation.

 

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact), and the Compact Commission, which is responsible for causing a new disposal facility to be developed within one of the member states. The Compact Commission selected Nebraska as the host state for the disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project. Our net investment in the Compact is approximately $7.4 million.

 

In December 1998, the Nebraska agencies responsible for considering the developer’s license application denied the application. Most of the utilities that had provided the project’s pre-construction financing, including WCNOC as well as the Compact Commission itself, filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the court entered a judgment of $151.4 million, about one-third of which constitutes prejudgment interest, in favor of the Compact Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. Following unsuccessful appeals of the decision by Nebraska, in August 2004 Nebraska and the Compact Commission settled the case. The settlement requires Nebraska to pay the Compact Commission a one-time amount of $140.5 million or, alternatively, four annual installments of $38.5 million beginning in August 2005. The parties agreed to dismiss all pending litigation and appeals relating to this matter. Once Nebraska makes its final payment, it will be relieved of its responsibility to host a disposal facility. Meanwhile, the Compact Commission is pursuing other strategies for providing disposal capability for waste generators in the Compact region.

 

Outages

 

Wolf Creek operates on an 18-month refueling and maintenance outage schedule that permits operations during every third calendar year without a refueling outage. Wolf Creek was shut down for 45 days in 2003 for its thirteenth scheduled refueling and maintenance outage, which began on October 18, 2003 and ended on December 2, 2003.

 

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During outages at the plant we meet our electric demand primarily with our fossil-fueled generating units and by purchasing power depending on availability and cost. As provided by the KCC, we amortize the incremental maintenance costs incurred for planned refueling outages evenly over the unit’s 18 month operating cycle. We do not defer and amortize the incremental fuel or purchased power costs incurred as a result of a refueling outage. Wolf Creek is scheduled to be taken off-line in the spring of 2005 for its fourteenth refueling and maintenance outage.

 

An extended or unscheduled shutdown of Wolf Creek could have a substantial adverse effect on our business, financial condition and consolidated results of operations because of higher replacement power and other costs and reduced amounts of power available to sell at wholesale. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or other concerns.

 

The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on their safety significance. Wolf Creek currently meets all NRC oversight objectives and receives the minimum regimen of NRC inspections. However, because of Wolf Creek’s recent experience with unscheduled outages, one additional unscheduled outage before September 30, 2005 may result in the NRC lowering the Wolf Creek rating for one performance indicator. This might require additional NRC inspections to evaluate possible corrective actions that if required might result in additional expense or disruption in Wolf Creek’s operation.

 

Nuclear Decommissioning

 

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that funds required for nuclear decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.

 

We expense nuclear decommissioning costs over the expected life of Wolf Creek. The amount we expense is based on an estimate of nuclear decommissioning costs that we will incur upon retirement of the plant. Nuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2004, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. Fair value approximated $91.1 million at December 31, 2004 and $80.1 million at December 31, 2003.

 

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the nuclear decommissioning study, the current-year funding and future funding. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount for its pro rata share of the plant.

 

We filed an updated nuclear decommissioning and dismantlement cost estimate with the KCC on August 30, 2002. Estimated costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied on site-specific, technical information, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s nuclear decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220.0 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

 

The KCC issued an order on April 16, 2003 approving the August 2002 nuclear decommissioning study for Wolf Creek. On June 2, 2003, we filed a funding schedule with the KCC to reflect the KCC’s April 16, 2003 order. On October 10, 2003, the KCC approved the funding schedule as filed without any change to our funding obligation. We expect to file an updated decommissioning cost study with the KCC by September 1, 2005.

 

We charge nuclear decommissioning costs to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the funding schedule in the KCC’s October 13, 2003 order. Electric rates charged to customers provide for recovery of these nuclear decommissioning costs over the life of Wolf Creek, which, as determined by the KCC for purposes of the funding schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear decommissioning

 

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fund by the time our license expires in 2025. We believe that the KCC approved funding level will be sufficient to meet the NRC minimum financial assurance requirement. However, our consolidated results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.

 

Competition and Deregulation

 

Electric utilities have historically operated in a rate-regulated environment. The Federal Energy Regulatory Commission (FERC), the federal regulatory agency having jurisdiction over our wholesale rates and transmission services, and other utilities have initiated steps expected to result in a more competitive environment for utility services in the wholesale market.

 

The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted FERC to order electric utilities to allow third parties to use their transmission systems to transport electric power to wholesale customers. In 1992, we agreed to permit third parties access to our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order encouraging the formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating open and more competitive markets in bulk power.

 

Regional Transmission Organization

 

We are a member of the Southwest Power Pool (SPP). On October 1, 2004, FERC granted RTO status to the SPP. As a result, if approved by the KCC, we expect to turn operational control of our transmission system over to the SPP RTO under its membership agreement and applicable tariff. The SPP RTO will operate our transmission system as part of an interconnected transmission system across eight states. The SPP will collect revenues attributable to the use of each member’s transmission system. Members and transmission customers will be able to transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. We believe each transmission owner generally retains the transmission capacity needed to serve its retail customers. Any additional transmission capacity will be sold on a first come/first served non-discriminatory basis. All transmission customers will be charged uniform rates for use of the transmission system, including entities that may sell power inside our certificated service territory. We do not expect that our participation in the SPP will have a material effect on our operations; however, we expect costs to increase due to the establishment of the RTO and associated markets. At this time, we are unable to quantify these costs because market implementation issues remain unresolved. We expect that we will recover these costs in rates we charge to our customers.

 

Regulation and Rates

 

As a Kansas electric utility, we are subject to the jurisdiction of the KCC, which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety.

 

As a result of an earlier KCC order, we will file a request for a rate review with the KCC by May 2, 2005, based on a test year consisting of the 12 months ended December 31, 2004.

 

Effective January 4, 2004, the “Hours of Service” regulations that govern the length of time that drivers may operate vehicles and the length of time they must be off-duty were revised. This legislation was designed to reduce accidents related to driver fatigue. Electric utilities were exempt from implementing these changes until September 2004. During restoration of electric service after a power outage, we must obtain a declaration of a state of emergency in order to gain an exception from these rules. Such an exception permits employees required to restore electric power to operate equipment for extended hours without the otherwise required off-duty time. The impact of this legislation could affect customer service and could result in increased operating costs if we have to hire additional employees or contractors or lengthen electric service outages.

 

On January 16, 2004, the KCC issued an order regarding electric service reliability for retail customers. The order was intended to help the KCC assess the reliability of retail electric service. Specifically, the KCC wanted

 

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to establish uniform definitions and requirements regarding service obligations, record keeping, customer notification and methods of reporting results to the KCC. On February 10, 2004, the North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from the investigation of the August 14, 2003 blackout in portions of the northeastern United States. These initiatives will impact our operations in a number of ways, including system relay protection, vegetation management and operator training. The NERC and the ten operating regions in the United States, including the SPP, are working together to determine what operating policies and planning standards changes are necessary to achieve the NERC’s goals. We are unable to estimate potential compliance costs at this time; however, it is likely that our annual capital and maintenance expenditure requirements will increase in the future.

 

Public Utility Holding Company Act of 1935

 

Westar Energy is a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) as a result of Westar Energy’s ownership of KGE and Westar Generating, Inc., each a wholly-owned subsidiary. Currently, Westar Energy claims an exemption from registration under the 1935 Act based on its operations being conducted “predominantly” within Kansas. Following a recent decision by the Securities and Exchange Commission (SEC) with respect to its interpretation of the criteria that must be satisfied to claim a “predominantly” intrastate exemption and as a result of the amount of sales of wholesale electricity outside of Kansas by Westar Energy’s energy marketing operations, it is possible that the SEC could question Westar Energy’s eligibility for an exemption from registration under the 1935 Act. In that event, we would evaluate our options, including filing an application for exemption and asking the SEC to formally consider that request, becoming a registered holding company, restructuring our operations in a manner that would allow us to maintain eligibility to claim an exemption or restructuring our organizational structure to consolidate all utility operations into one entity so that Westar Energy is no longer a utility holding company.

 

In the event we elect to register Westar Energy as a holding company, the 1935 Act and related regulations issued by the SEC would govern its activities and the activities of its subsidiaries with respect to the acquisition, issuance and sale of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters. We are unable to predict whether Westar Energy will continue to be eligible for an exemption for registration under the 1935 Act, however, we believe that Westar Energy becoming a registered holding company under the 1935 Act or taking steps to reorganize our corporate structure to avoid registration would not have a material impact on our consolidated financial position, results of operations or cash flows.

 

Environmental Matters

 

General

 

We are subject to various federal, state and local environmental laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharges of effluents into water and the use of water, and the handling and disposal of hazardous substances and wastes. These laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for our new, existing or modified facilities. If we fail to comply with such laws and regulations, we could be fined or otherwise sanctioned by regulators. In addition, under certain laws, we could be responsible for costs relating to contamination at our current and former facilities or at third-party waste disposal sites. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations.

 

Environmental laws and regulations affecting power plants are overlapping, complex, subject to changes in interpretation and implementation and have tended to become more stringent over time. Although we believe that we can recover in rates the costs relating to compliance with such laws and regulations, there can be no assurance that we will be able to recover all or any such increased costs from our customers or that our business, consolidated financial condition or results of operations will not be materially and adversely affected as a result of costs to comply with such existing and future laws and regulations.

 

Air Emissions

 

The Clean Air Act, state laws and implementing regulations impose, among other things, limitations on major pollutants, including sulfur dioxide (SO2), particulate matter and nitrogen oxides (NOx).

 

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Certain Kansas Department of Health and Environment (KDHE) regulations applicable to our generating facilities prohibit the emission of SO2 in excess of certain levels. In order to meet these standards, we use low-sulfur coal, fuel oil and natural gas and have equipped our generating facilities with pollution control equipment.

 

In addition, we must comply with the provisions of the Clean Air Act Amendments of 1990 that require a two-phase reduction in some emissions. We have installed continuous monitoring and reporting equipment in order to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II SO2 and NOx requirements.

 

Title IV of the Clean Air Act created an SO2 allowance and trading program as part of the federal acid rain program. Under the allowance and trading program, the Environmental Protection Agency (EPA) allocated annual SO2 emissions allowances for each affected emitting unit. An SO2 allowance is a limited authorization to emit one ton of SO2 during a calendar year. At the end of each year, each emitting unit must have enough allowances to cover its emissions for that year. Allowances are tradable so that operators of affected units that are anticipated to emit SO2 in excess of their allowances may purchase allowances from operators of affected units that are anticipated to emit SO2 in an amount less than their allowances. Because of strong demand for generation during 2002 and 2003, we consumed more SO2 allowances than were allocated to us by the EPA. We made up the shortfall by buying allowances. In 2004, we had enough emissions allowances to meet planned generation and we expect to have enough in 2005. In future years, we expect to purchase SO2 allowances in order to meet the acid rain requirements of the Clean Air Act. We cannot estimate the cost at this time, but anticipate these costs may be material. The pricing of emissions allowances is unpredictable and may change over time.

 

On January 30, 2004, the EPA published two proposed air quality rules referred to as the “Interstate Air Quality Rule” and the “Utility Mercury Reduction Rule” that, if adopted, would impact our operations. In an attempt to address the impact of interstate transport of air pollutants on downwind states, the proposed Clean Air Interstate Rule would require reductions of SO2 and NOx in certain states, including Kansas, in two separate phases. The first reductions would be required in 2010 and the second in 2015.

 

The proposed Utility Mercury Reduction Rule sets out two approaches for requiring subject power plants to control mercury and nickel emissions. The first option, a traditional command and control approach, would require subject plants to meet Hazardous Air Pollutant emissions standards for mercury and nickel based on the application of maximum achievable control technology. The second option would establish standards of performance limiting mercury and nickel emissions, and include a “cap and trade” program for mercury emissions. The EPA is expected to issue its final rule in 2005. New requirements for reductions of nickel emissions will be applicable only to our generating facilities that burn a significant amount of oil. Based on currently available information, we cannot estimate our costs to comply with these two proposed rule changes, but these costs could be material.

 

We may be required to further reduce emissions of SO2, NOx, particulate matter, mercury and carbon dioxide (CO2) as a result of various other current or pending laws, including, in particular:

 

    the EPA’s national ambient air quality standards for particulate matter and ozone,

 

    the EPA’s regional haze rules, designed to reduce SO2, NOx and particulate matter emissions, and

 

    additional legislation introduced in the past few years in Congress, such as the various “multi-pollutant” bills sponsored by members of Congress requiring reductions of CO2, NOx, SO2 and mercury, and the “Clear Skies” legislation proposed by the President, which would cap emissions of NOx, SO2 and mercury.

 

Based on currently available information, we cannot estimate our costs to comply with these proposed laws, but such costs could be material.

 

EPA New Source Review

 

The EPA is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to New Source Review requirements or New Source Performance Standards under Section 114(a) of the Clean Air Act (Section 114). These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could have reasonably been expected to result in a significant net increase in emissions. The Clean Air Act requires companies to obtain permits and, if

 

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necessary, install control equipment to remove emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

 

The EPA has requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.

 

We are in discussions with the EPA concerning this matter in an attempt to reach a settlement. We expect that any settlement with the EPA could require us to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years. Additionally, we might be required to update or install emissions controls at our other coal-fired plants, pay fines or penalties, or take other remedial action. Together, these costs could be material. The EPA has informed us that it has referred this matter to the Department of Justice (DOJ) for the DOJ to consider whether to pursue an enforcement action in federal district court. We believe that costs related to updating or installing emissions controls would qualify for recovery through rates. If we were to reach a settlement with the EPA, we may be assessed a penalty. The penalty could be material and may not be recovered in rates.

 

Manufactured Gas Sites

 

We have been associated with a number of former manufactured gas sites located in Kansas and Missouri that may contain coal tar and other potentially harmful materials.

 

We and the KDHE entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Through December 31, 2004, the costs incurred for preliminary site investigation and risk assessment have been minimal. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the Kansas sites, our liability for twelve of the Kansas sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three Kansas sites. With respect to two of those sites, we are currently either conducting or completing remediation activities and, with respect to the third site, we will begin investigation activities in the near future.

 

Our liability for our former manufactured gas sites in Missouri is limited by an environmental indemnity agreement with Southern Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our future liability for these sites is capped at $7.5 million and terminates in 2009.

 

Solid Waste Landfills

 

We operate solid waste landfills at Jeffrey, Lawrence and Tecumseh Energy Centers for the single purpose of disposing of coal combustion waste material. Additionally, there is one retired landfill at each of the Lawrence and Neosho Energy Centers. All landfills are permitted by the KDHE. The operating landfill at Lawrence Energy Center is projected to be full by late 2007 or early 2008 requiring us to permit and construct a new landfill at this site. We began the process of obtaining this permit in late 2003. We will continue to work with the appropriate regulatory agencies to ensure that the new landfill and expansion of the existing landfill will meet the operating requirements of the Lawrence Energy Center.

 

EMPLOYEES

 

As of February 28, 2005, we employed approximately 2,100 people. Our current contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers extends through June 30, 2005. The contract is currently under negotiation. The contract covered approximately 1,200 employees as of February 28, 2005.

 

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ACCESS TO COMPANY INFORMATION

 

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge either through our Internet website at www.wr.com or by responding to requests addressed to our investor relations department. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The information contained on our Internet website is not part of this document.

 

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RISK FACTORS

 

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the performance of our customers. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

 

Our Revenues Depend Upon Rates Determined by the KCC

 

The KCC regulates many aspects of our business and operations, including the retail rates that we may charge customers for electric service. Retail rates are set by the KCC using a cost-of-service approach that takes into account historical operating expenses, fixed obligations and recovery of capital investments, including potentially stranded obligations. Using this approach, the KCC sets rates at a level calculated to recover such costs, adjusted to reflect known and measurable changes, and a permitted return on investment. Other parties to a rate review or the KCC staff may contend that our current or proposed rates are excessive. In July 2003, the KCC approved a stipulation and agreement that requires us to file for a rate review, which may or may not include a request for a change in rates, by May 2, 2005, and to pay customer rebates of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. The rates permitted by the KCC in the rate review will determine our revenues for the succeeding periods and may have a material impact on our consolidated earnings, cash flows and financial position, as well as our ability to maintain our common stock dividend at current levels or to increase our dividend in the future. We are unable to predict the outcome of the rate review.

 

Some of Our Costs May not be Fully Recovered in Retail Rates

 

Once established by the KCC, our rates remain fixed until changed in a subsequent rate review. We may at any time elect to file a rate review to request a change in our rates or intervening parties may request that the KCC review our rates for possible adjustment, subject to any limitations that may have been ordered by the KCC. Earnings could be reduced to the extent that increases in our operating costs increase more than our revenues during the period between rate reviews, which may occur because of maintenance and repair of plants, fuel and purchased power expenses, employee or labor costs, inflation or other factors.

 

Equipment Failures and Other External Factors Can Adversely Affect Our Results

 

The generation and transmission of electricity requires the use of expensive and complicated equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must either produce replacement power from our less efficient units or purchase power from others at unpredictable cost in order to supply our customers and perform our contractual agreements. This can increase our costs materially and prevent or limit us from selling power at wholesale, thus reducing our profits. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. These factors, as well as weather, interest rates, economic conditions, fuel availability and prices, price volatility of fuel and other commodities and transportation availability and costs are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position. We engage in energy marketing transactions to reduce risk from market fluctuations, enhance system reliability and increase profits. The events mentioned above could reduce our ability to participate in energy marketing opportunities, which could reduce our profits.

 

We May Have Material Financial Exposure Under the Clean Air Act and Other Environmental Regulations

 

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements under the Clean Air Act. This notification was delivered as part of an investigation by the EPA regarding maintenance activities that have been conducted since 1980 at Jeffrey Energy Center. The EPA has informed us that it has referred this matter to the DOJ for it to consider whether to pursue an enforcement action in federal district court. The remedy for a violation could include fines and penalties and an order to install new emission control systems, the cost of which could be material.

 

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Our activities are subject to stringent environmental regulation by federal, state, and local governmental authorities. These regulations generally involve discharges of effluents into the water, emissions into the air, the use of water, and hazardous substance and waste handling, remediation and disposal, among others. Congress also may consider legislation and the EPA may propose new regulations or change existing regulations that could require us to further restrict or reduce certain emissions at our plants. Legislation, proposed regulations or changes in regulations, if adopted, could impose additional costs on the operation of our power plants. Although we generally recover such costs through our rates, there can be no assurance that we would be able to recover all or any increased costs relating to compliance with environmental regulations from our customers or that our business, consolidated financial condition or results of operations would not be materially and adversely affected. We have made and will continue to make capital and other expenditures to comply with environmental laws and regulations. There can be no assurance that such expenditures will not have a material adverse effect on our business, consolidated financial condition or results of operations.

 

Competitive Pressures from Electric Industry Deregulation Could Adversely Affect Our Revenues and Reported Earnings

 

We currently apply the accounting principles of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business and at December 31, 2004 had recorded $413.7 million of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either as a result of the establishment of retail competition in Kansas or an expectation that permitted rates would not allow us to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Neither the Kansas Legislature nor the KCC has taken action in the recent past to establish retail competition in our service territory.

 

We Face Financial Risks From Our Ownership Interest in the Wolf Creek Nuclear Facility

 

Risks of substantial liability arise from the ownership and operation of nuclear facilities, including, among others, structural problems at a nuclear facility, the storage, handling and disposal of radioactive materials, limitations on the amounts and types of insurance coverage commercially available and uncertainties with respect to the technological aspects of nuclear decommissioning at the end of their useful lives and anticipated increases in the cost of nuclear decommissioning and costs or measures associated with public safety. In the event of an extended or unscheduled outage at Wolf Creek, we would be required to generate power from less efficient units, purchase power in the open market to replace the power normally produced at Wolf Creek and we would have less power available for sale by us in the wholesale markets. Such purchases would subject us to the risk of increased energy prices and, depending on the length of the outage and the level of market prices, could adversely affect our cash flow. If we were not permitted by the KCC to recover these costs, such events could have an adverse impact on our consolidated financial condition.

 

We May Face Liability In Ongoing Lawsuits and Investigations

 

We and certain of our former and present directors and officers are defendants in civil litigation alleging violations of the securities laws. In addition, we continue to cooperate in investigations by a federal grand jury, the SEC and the DOJ into events that occurred at our company during the years prior to 2003. Our former president, chief executive officer and chairman and our former executive vice president and chief strategic officer have asserted significant claims against us in connection with the termination of their employment and the publication of the report of the special committee of our board of directors. An adverse result in any of these matters could result in damages, fines or penalties in amounts that could be material and adversely affect our consolidated results and financial condition. Management believes that it is not currently possible to estimate the potential impact of the ultimate resolution of these matters.

 

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EXECUTIVE OFFICERS OF THE COMPANY

 

Name


   Age

    

Present Office


  

Other Offices or Positions
Held During the Past Five Years


James S. Haines, Jr.

   58     

Director, Chief Executive Officer and President (since December 2002)

  

The University of Texas at El Paso

Adjunct Professor and Skov Professor of Business Ethics (January 2002 to Present)

El Paso Electric Company

Director, President and Chief Executive Officer
(May 1996 to November 2001)

William B. Moore

   52     

Executive Vice President and Chief Operating Officer (since December 2002)

  

Saber Partners, LLC

Senior Managing Director and Senior Advisor
(October 2000 to December 2002)

Westar Energy, Inc.

Executive Vice President, Chief Financial Officer and Treasurer
(May 1999 to August 2000)

Mark A. Ruelle

   43     

Executive Vice President and Chief Financial Officer (since January 2003)

  

Sierra Pacific Resources, Inc.

President, Nevada Power Company (June 2001 to May 2002)

Senior Vice President, Chief Financial Officer (March 1997 to May 2001)

Douglas R. Sterbenz

   41     

Senior Vice President, Generation and Marketing (since October 2001)

  

Westar Energy, Inc.

Senior Director, Bulk Power Marketing (January 1999 to October 2001)

Bruce A. Akin

   40     

Vice President, Administrative Services (since December 2001)

  

Westar Energy, Inc.

Executive Director, Business Services (October 2001 to December 2001)

Executive Director, Human Resources (July 1999 to October 2001)

Kelly B. Harrison

   46     

Vice President, Regulatory (since December 2001)

  

Westar Energy, Inc.

Executive Director, Regulatory (October 2001 to December 2001)

Senior Director, Restructuring and Rates (October 1999 to October 2001)

Larry D. Irick

   48     

Vice President, General Counsel and Corporate Secretary (since February 2003)

  

Westar Energy, Inc.

Vice President and Corporate Secretary (December 2001 to February 2003)

Corporate Secretary (May 2000 to December 2001)

Executive Director, Law (May 1999 to May 2000)

Peggy S. Loyd

   47     

Vice President, Corporate Compliance and Internal Audit (since March 2003)

  

Westar Energy, Inc.

Vice President, Financial Services (May 2000 to March 2003)

Executive Director, Financial Services (January 1999 to May 2000)

James J. Ludwig

   46     

Vice President, Public Affairs (since January 2003)

  

Westar Energy, Inc.

Senior Director, Regulatory Affairs (July 1995 to October 2001)

Lee Wages

   56     

Vice President, Controller (since December 2001)

  

Westar Energy, Inc.

Controller (July 1999 to December 2001)

 

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ITEM 2. PROPERTIES

 

                    Unit Capacity (MW) By Owner

Name


  Location

  Unit
No.


  Year
Installed


  Principal
Fuel


  Westar
Energy


  KGE

  Total
Company


Abilene Energy Center:

  Abilene, Kansas                        

Combustion Turbine

         1   1973   Gas   72.0   —     72.0

Gordon Evans Energy Center:

  Colwich, Kansas                        

Steam Turbines

         1   1961   Gas—Oil   —     149.0   149.0
           2   1967   Gas—Oil   —     383.0   383.0

Combustion Turbines

         1   2000   Gas   74.0   —     74.0
           2   2000   Gas   74.0   —     74.0
           3   2001   Gas   151.0   —     151.0

Diesel Generator

         1   1969   Diesel   —     3.0   3.0

Hutchinson Energy Center:

  Hutchinson, Kansas                        

Steam Turbines

         1   1950   Gas—Oil   17.0   —     17.0
           2   1950   Gas—Oil   16.0   —     16.0
           3   1951   Gas—Oil   28.0   —     28.0
           4   1965   Gas—Oil   173.0   —     173.0

Combustion Turbines

         1   1974   Gas   54.0   —     54.0
           2   1974   Gas   55.0   —     55.0
           3   1974   Gas   56.0   —     56.0
           4   1975   Diesel   77.0   —     77.0

Diesel Generator

         1   1983   Diesel   3.0   —     3.0

Jeffrey Energy Center (84%):

  St. Marys, Kansas                        

Steam Turbines

         1(a)   1978   Coal   471.0   147.0   618.0
           2(a)   1980   Coal   470.0   147.0   617.0
           3(a)   1983   Coal   475.0   149.0   624.0

Wind Turbines

         1(a)   1999   —     0.5   0.1   0.6
           2(a)   1999   —     0.5   0.1   0.6

LaCygne Station (50%):

  LaCygne, Kansas                        

Steam Turbines

         1(a)   1973   Coal   —     344.0   344.0
           2(b)   1977   Coal   —     337.0   337.0

Lawrence Energy Center:

  Lawrence, Kansas                        

Steam Turbines

         3   1954   Coal   54.0   —     54.0
           4   1960   Coal   122.0   —     122.0
           5   1971   Coal   372.0   —     372.0

Murray Gill Energy Center:

  Wichita, Kansas                        

Steam Turbines

         1   1952   Gas   —     40.0   40.0
           2   1954   Gas—Oil   —     71.0   71.0
           3   1956   Gas—Oil   —     104.0   104.0
           4   1959   Gas—Oil   —     102.0   102.0

Neosho Energy Center:

  Parsons, Kansas                        

Steam Turbine

         3   1954   Gas—Oil   —     63.0   63.0

State Line (40%):

  Joplin, Missouri                        

Combined Cycle

      2-1(a)   2001   Gas   65.0   —     65.0
        2-2(a)   2001   Gas   64.0   —     64.0
        2-3(a)   2001   Gas   71.0   —     71.0

Tecumseh Energy Center:

  Tecumseh, Kansas                        

Steam Turbines

         7   1957   Coal   75.0   —     75.0
           8   1962   Coal   129.0   —     129.0

Combustion Turbines

         1   1972   Gas   18.0   —     18.0
           2   1972   Gas   20.0   —     20.0

Wolf Creek Generating Station (47%):

  Burlington, Kansas                        

Nuclear

         1(a)   1985   Uranium   —     548.0   548.0
                   
 
 

Total

                  3,257.0   2,587.2   5,844.2
                   
 
 

 

(a) We jointly own Jeffrey Energy Center (84%), LaCygne 1 generating unit (50%), Wolf Creek Generating Station (47%) and State Line (40%). Unit capacity amounts reflect our ownership only.

 

(b) In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the LaCygne 2 generating unit.

 

We own approximately 6,100 miles of transmission lines, approximately 23,600 miles of overhead distribution lines and approximately 3,300 miles of underground distribution lines.

 

Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.

 

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ITEM 3. LEGAL PROCEEDINGS

 

On September 21, 2004, a grand jury in Travis County, Texas, indicted us on charges that a $25,000 contribution by us in May 2002 to a Texas political action committee violated Texas election laws. We believe the indictment is without merit and we intend to vigorously defend against the charges. If convicted, the court could impose a fine of up to $20,000 or, in certain circumstances, in an amount not to exceed twice the amount caused to be lost by the commission of the felony. As a result of the indictment, the federal government could suspend our status as a government contractor. Upon a conviction, the federal government could bar us from acting as a government contractor. We are taking action to ensure that neither of these events occur, but we do not know whether we will be successful. We are unable to predict the ultimate impact either suspension or loss of our status as a government contractor would have on our consolidated financial position, results of operations and cash flows.

 

Information on other legal proceedings is set forth in Notes 3, 15, 17, 18 and 20 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies — EPA New Source Review,” “Legal Proceedings,” “Ongoing Investigations” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2004.

 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

 

STOCK TRADING

 

Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of March 1, 2005, there were 29,503 common shareholders of record. For information regarding quarterly common stock price ranges for 2004 and 2003, see Note 26 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

 

DIVIDENDS

 

Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for each series.

 

Quarterly dividends on common stock and preferred stock have historically been paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. On November 23, 2004, our board of directors declared a quarterly dividend of $0.23 per share, payable January 3, 2005.

 

Our articles of incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless we meet certain capitalization ratios and other conditions. We provide further information on these restrictions in Note 19 of the Notes to Consolidated Financial Statements, “Common and Preferred Stock.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock.

 

For additional information on dividends, see Note 19 of the Notes to Consolidated Financial Statements, “Common and Preferred Stock,” included herein.

 

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Table of Contents

 

ITEM 6. SELECTED FINANCIAL DATA

 

     For the Year Ended December 31,

     2004

   2003

   2002 (a)

    2001

    2000

     (In Thousands)

Income Statement Data:

                                    

Sales

   $ 1,464,489    $ 1,461,143    $ 1,423,151     $ 1,308,536     $ 1,361,006

Income from continuing operations before accounting change

     100,080      162,915      88,816       59,333       192,696

Earnings (loss) available for common stock

     177,900      84,042      (793,400 )     (21,771 )     135,352
     As of December 31,

     2004

   2003

   2002

    2001

    2000

     (In Thousands)

Balance Sheet Data:

                                    

Total assets

   $ 5,085,711    $ 5,742,975    $ 6,756,666     $ 7,718,764     $ 7,887,746

Long-term obligations and mandatorily redeemable preferred stock (b)

     1,724,967      2,259,880      3,225,556       2,915,153       2,938,832
     For the Year Ended December 31,

     2004

   2003

   2002 (a)

    2001

    2000

Common Stock Data:

                                    

Basic earnings per share available for common stock from continuing operations before accounting change

   $ 1.19    $ 2.24    $ 1.23     $ 0.83     $ 2.78

Basic earnings (loss) per share available for common stock

   $ 2.14    $ 1.16    $ (11.06 )   $ (0.31 )   $ 1.96

Dividends declared per share

   $ 0.80    $ 0.76    $ 1.20     $ 1.20     $ 1.44

Book value per share

   $ 16.13    $ 13.98    $ 13.41     $ 25.64     $ 27.28

Average equivalent common shares outstanding (in thousands)

     82,941      72,429      71,732       70,650       68,962

(a) See Note 4 of the Notes to Consolidated Financial Statements, “Discontinued Operations — Sale of Protection One and Protection One Europe” for discussion of impairment charges that are the primary cause of our losses.

 

(b) Includes long-term debt, capital leases, affiliate long-term debt and shares subject to mandatory redemption.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

INTRODUCTION

 

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central United States under the regulation of the KCC and FERC.

 

Our focus during 2004 was the continued reduction of our debt and interest expense, primarily through issuing stock, the sale of our interest in Protection One and by refinancing some of our debt at lower interest rates. In 2004, we reduced our debt by $533.4 million.

 

Our goals for 2005 are to improve our core utility business by improving our credit quality, establishing a successful clean air plan, completing a successful rate review, improving our service quality, making our operations more efficient and continuing our involvement in community affairs.

 

Key factors affecting our business in any given period include the weather, the economic well-being of our Kansas service territory, performance of our electric generating facilities, conditions in fuel markets and the markets for wholesale electricity and the cost of dealing with public policy initiatives.

 

As you read Management’s Discussion and Analysis, please refer to our consolidated financial statements and the accompanying notes, which contain our operating results.

 

CRITICAL ACCOUNTING ESTIMATES

 

We base our discussion and analysis of financial condition and results of operations on our consolidated financial statements, which have been prepared in conformity with Generally Accepted Accounting Principles (GAAP). Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or susceptibility of matters to change.

 

Pension Benefit Plans

 

We calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively.

 

In accounting for our retirement plans and other post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension benefit plans, which include our portion of WCNOC’s costs, are impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs and employee demographics including age, compensation levels and employment periods. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the current and future periods, or on the amount of related liabilities reflected on our consolidated balance sheets or may also require cash contributions.

 

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The following table shows the annual impact of a 0.5% decrease in our pension plan discount rate and rate of return on plan assets. If the discount rate increased by 0.5%, the impact would be a similar amount in the opposite direction.

 

    

Change in

Assumption


 

Annual

Increase in
Projected

Benefit

Obligation


  

Annual

Increase in

Pension

Liability


  

Annual

Increase in

Projected

Pension

Expense


              (In Thousands)     

Discount rate

   0.5% decrease   $ 35,227    $ 32,134    $ 2,850

Rate of return on plan assets

   0.5% decrease     —        —        2,299

 

The following table shows the annual impact of a 0.5% decrease in our post-retirement plan discount rate and rate of return on plan assets. If the discount rate increased by 0.5%, the impact would be a similar amount in the opposite direction.

 

    

Change in

Assumption


 

Annual

Increase in
Projected

Benefit

Obligation


  

Annual

Increase in

Post-retirement

Liability


  

Annual

Increase in

Projected

Post-retirement

Expense


              (In Thousands)     

Discount rate

   0.5% decrease   $ 6,243    $ —      $ 333

Rate of return on plan assets

   0.5% decrease     —        —        120

 

Revenue Recognition – Energy Sales

 

We recognize revenues from retail energy sales upon delivery to the customer and include an estimate for energy delivered but unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured against billed sales. At December 31, 2004, we had estimated unbilled revenue of $47.6 million.

 

We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. Unless related to fuel, we include the net mark-to-market change in sales on our consolidated statements of income (loss). We record the resulting unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. Prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

 

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The tables below show fair value of energy marketing contracts outstanding for the year ended December 31, 2004, their sources and maturity periods.

 

     Fair Value of Contracts

 
     (In Thousands)  

Net fair value of contracts outstanding at the beginning of the period

   $ 10,464  

Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period

     (7,293 )

Changes in fair value of contracts outstanding at the beginning and end of the period

     (2,590 )

Fair value of new contracts entered into during the period

     5,500  
    


Fair value of contracts outstanding at the end of the period

   $ 6,081  
    


 

The sources of the fair values of the financial instruments related to these contracts are summarized in the following table.

 

     Fair Value of Contracts at End of Period

Sources of Fair Value


  

Total

Fair Value


  

Maturity

Less Than

1 Year


  

Maturity

1-3 Years


   

Maturity

4-5 Years


     (In Thousands)

Prices provided by other external sources (swaps and forwards)

   $ 2,255    $ 1,396    $ (377 )   $ 1,236

Prices based on the Black Option Pricing model (options and other) (a)

     3,826      1,328      500       1,998
    

  

  


 

Total fair value of contracts outstanding

   $ 6,081    $ 2,724    $ 123     $ 3,234
    

  

  


 


(a) The Black Option Pricing model is a variant of the Black-Scholes Option Pricing model.

 

Income Taxes

 

We use the asset and liability method of accounting for income taxes as required by SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties.

 

We record deferred tax assets for capital loss, operating loss and tax credit carryforwards. However, when there are not sufficient sources of future capital gain income or taxable income to realize the benefit of the capital loss, operating loss or tax credit carryforwards, we reduce the deferred tax assets by a valuation allowance. We recognize a valuation allowance if, based on the weight of available evidence, it is considered more likely than not that some portion or all of the deferred tax asset will not be realized. We report the effect of a change in the valuation allowance in the current period tax expense.

 

OPERATING RESULTS

 

We evaluate operating results based on basic earnings (loss) per share. We have various classifications of sales, defined as follows:

 

Retail: Sales of energy made to residential, commercial and industrial customers.

 

Other retail: Sales of energy for lighting public streets and highways, net of revenues reserved for rebates.

 

Tariff-based wholesale: Includes the sales of electricity to electric cooperatives, municipalities and other electric utilities, the rate for which is generally based on cost

 

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as prescribed by FERC tariffs, and changes in valuations of contracts that have yet to settle.

 

Market-based wholesale: Includes sales of electricity to other wholesale customers, the rate for which is based on prevailing market prices as allowed by our FERC approved market-based tariff, and changes in valuations of contracts that have yet to settle.

 

Energy marketing: Includes: (1) market-based energy transactions unrelated to our generation or the needs of our regulated customers; (2) financially settled products and physical transactions sourced outside our control area; and (3) changes in valuations for contracts that have yet to settle that may not be recorded either in cost of fuel or tariff- or market-based wholesale revenues.

 

Transmission: Reflects transmission revenues received, including those based on a tariff with the SPP.

 

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others.

 

Regulated electric utility sales are significantly impacted by such things as rate regulation, customer conservation efforts, wholesale demand, the overall economy of our service area, the weather and competitive forces. Our wholesale sales are impacted by, among other factors, demand, cost of fuel and purchased power, price volatility and available generation capacity.

 

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Table of Contents

2004 compared to 2003: Below we discuss our operating results for the year ended December 31, 2004 as compared to the results for the year ended December 31, 2003.

 

     Year Ended December 31,

 
     2004

    2003

    Change

    % Change

 
     (In Thousands, Except Per Share Amounts)  

SALES:

                              

Residential

   $ 425,150     $ 432,955     $ (7,805 )   (1.8 )

Commercial

     386,991       382,585       4,406     1.2  

Industrial

     239,518       240,538       (1,020 )   (0.4 )

Other retail

     (46 )     5,363       (5,409 )   (100.9 )
    


 


 


     

Total Retail Sales

     1,051,613       1,061,441       (9,828 )   (0.9 )

Tariff-based wholesale

     143,868       140,687       3,181     2.3  

Market-based wholesale

     140,465       125,995       14,470     11.5  

Energy marketing

     26,321       31,881       (5,560 )   (17.4 )

Transmission (a)

     77,540       76,379       1,161     1.5  

Other

     24,682       24,760       (78 )   (0.3 )
    


 


 


     

Total Sales

     1,464,489       1,461,143       3,346     0.2  
    


 


 


     

OPERATING EXPENSES:

                              

Fuel used for generation

     353,617       342,522       11,095     3.2  

Purchased power

     66,171       47,790       18,381     38.5  

Operating and maintenance

     412,002       371,372       40,630     10.9  

Depreciation and amortization

     169,310       167,236       2,074     1.2  

Selling, general and administrative

     173,498       160,825       12,673     7.9  
    


 


 


     

Total Operating Expenses

     1,174,598       1,089,745       84,853     7.8  
    


 


 


     

INCOME FROM OPERATIONS

     289,891       371,398       (81,507 )   (21.9 )
    


 


 


     

OTHER INCOME (EXPENSE):

                              

Investment earnings

     16,746       21,189       (4,443 )   (21.0 )

ONEOK dividends

     —         17,316       (17,316 )   (100.0 )

Gain on sale of ONEOK stock

     —         99,327       (99,327 )   (100.0 )

Loss on extinguishment of debt and settlement of putable/callable notes

     (18,840 )     (26,455 )     7,615     28.8  

Other income

     2,756       2,854       (98 )   (3.4 )

Other expense

     (14,879 )     (16,590 )     1,711     10.3  
    


 


 


     

Total Other Income (Expense)

     (14,217 )     97,641       (111,858 )   (114.6 )
    


 


 


     

Interest expense

     142,151       224,356       (82,205 )   (36.6 )
    


 


 


     

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     133,523       244,683       (111,160 )   (45.4 )

Income tax expense

     33,443       81,768       (48,325 )   (59.1 )
    


 


 


     

INCOME FROM CONTINUING OPERATIONS

     100,080       162,915       (62,835 )   (38.6 )

Results of discontinued operations, net of tax

     78,790       (77,905 )     156,695     201.1  
    


 


 


     

NET INCOME

     178,870       85,010       93,860     110.4  

Preferred dividends

     970       968       2     0.2  
    


 


 


     

EARNINGS AVAILABLE FOR COMMON STOCK

   $ 177,900     $ 84,042     $ 93,858     111.7  
    


 


 


     

BASIC EARNINGS PER SHARE

   $ 2.14     $ 1.16     $ 0.98     84.5  
    


 


 


     

(a)    Transmission: Includes an SPP network transmission tariff. In 2004, our transmission costs were approximately $66.6 million. This amount, less $4.3 million that was retained by the SPP as administration cost, was returned to us as revenues. In 2003, our transmission costs were approximately $65.3 million with an administration cost of $5.7 million retained by the SPP.

 

The following table reflects changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity, for the two years ended December 31, 2004 and 2003. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to electricity we generate.

 

        

   

     2004

    2003

    Change

    % Change

 
     (Thousands of MWh)        

Residential

     5,925       6,031       (106 )   (1.8 )

Commercial

     6,867       6,801       66     1.0  

Industrial

     5,470       5,448       22     0.4  

Other retail

     102       104       (2 )   (1.9 )
    


 


 


     

Total Retail

     18,364       18,384       (20 )   (0.1 )

Tariff-based wholesale

     4,573       4,747       (174 )   (3.7 )

Market-based wholesale

     4,115       3,919       196     5.0  
    


 


 


     

Total

     27,052       27,050       2     —    
    


 


 


     

 

Our retail customers used less energy and our sales decreased because of cooler weather during the summer. When measured by cooling degree days, the weather during 2004 was 12% cooler than during 2003 and 16% below the 20-year average. We measure cooling degree days at weather stations we believe to be generally reflective of conditions in our service territory. The accrual for rebates to be paid to customers in 2005 and 2006 pursuant to the

 

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Table of Contents

July 25, 2003 KCC order also reduced revenues from retail sales. During 2004, we accrued $8.5 million as compared to $3.5 million accrued during 2003.

 

Market-based wholesale sales increased due primarily to increased sales volumes and an approximate 6% increase in the average price per MWh. As a result of the milder weather, we had additional energy production available for sale at certain times during the year that was not needed to serve our retail and tariff-based wholesale customers. Increased sales volumes accounted for approximately $6.7 million of the increased market-based wholesale sales and higher average market prices accounted for approximately $7.8 million of the increase. Energy marketing sales declined because we had less favorable changes in 2004 as compared to the favorable changes in 2003 in the settlement and the fair value of positions receiving mark-to-market accounting treatment.

 

Fuel expense increased due primarily to increases in the cost of fossil fuels, although we used approximately 2% less fuel for generation due to the lower demand caused by the cooler weather and due to unplanned outages or reduced operating capability experienced at some of our generating units at various times throughout 2004. The average equivalent availability factor for our system was 87% during 2004 compared to 90% in the prior year, due largely to the unavailability of some of our coal-fired generating units. As a result of the cooler weather and the reduced availability of our coal-fired generating units, we decreased the amount of coal burned, and consequently reduced our total expense for coal. However, the cost of natural gas and oil that we used at other generating facilities to compensate for the unplanned outages or reduced operating capability, increased our total fuel expense.

 

Purchased power expense increased due primarily to a 34% increase in volumes purchased during 2004 as compared to 2003. At times, it was more economical to purchase power than to operate our available generating units. This was due to unplanned outages or reduced operating capability of our coal-fired generating units at certain times, and the availability of economically priced power due to cooler weather in our region.

 

During 2003, we recorded as an offset to operating and maintenance expense a gain of $11.9 million on the sale of utility assets. The absence of a similar offset in 2004 accounted for 29% of the increase in operating and maintenance expense in 2004. The remainder of the increase was caused primarily by increased expenses associated with maintenance at Jeffrey Energy Center, increased planned and unplanned unit maintenance at various other generating units, increased maintenance of the distribution system, an increase in taxes other than income tax and an increase in the transmission costs. During 2004, increased maintenance of our generating units accounted for 23% of the increase in operating and maintenance expenses. The increase in distribution expenses accounted for 17% of the increase in operating and maintenance expenses. Distribution expenses increased due to increased staffing levels and higher costs associated with the termination of portions of the ONEOK shared services agreement as discussed in Note 24 of the Notes to Consolidated Financial Statements, “Related Party Transactions—ONEOK Shared Services Agreement.” The change in taxes other than income tax accounted for 22% of the increase in operating and maintenance expenses. An increase in transportation costs accounted for 3% of the increase in operating and maintenance expenses.

 

Selling, general and administrative expenses increased due primarily to an increase in legal fees, including amounts we were required to advance for fees incurred by David C. Wittig, our former president, chief executive officer and chairman, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, related to the defense of criminal charges against them, and fees associated with the pending shareholder class action and derivative lawsuits.

 

The total other expense during 2004 was due primarily to the loss incurred on the extinguishment of debt. The total other income during 2003 was due primarily to the gain on the sale of our ONEOK stock and dividends received from ONEOK in 2003. This gain was partially offset by the loss recorded on the extinguishment of debt and the settlement of notes during 2003.

 

Interest expense decreased in 2004 due to lower debt balances and lower interest rates due to refinancing activities as discussed below in “Liquidity and Capital Resources.”

 

Income from discontinued operations was $78.8 million in 2004. The results recorded for 2004 include the settlement of previously pending issues as discussed in Note 4 of the Notes to Consolidated Financial Statements, “Discontinued Operations – Sale of Protection One and Protection One Europe.” This compares to a loss from discontinued operations of $77.9 million in 2003.

 

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2003 compared to 2002: Below we discuss our operating results for the year ended December 31, 2003 as compared to the results for the year ended December 31, 2002.

 

     Year Ended December 31,

 
     2003

    2002

    Change

    %
Change


 
     (In Thousands, Except Per Share Amounts)  

SALES:

                              

Residential

   $ 432,955     $ 442,106     $ (9,151 )   (2.1 )

Commercial

     382,585       385,375       (2,790 )   (0.7 )

Industrial

     240,538       242,847       (2,309 )   (1.0 )

Other retail

     5,363       8,071       (2,708 )   (33.6 )
    


 


 


     

Total Retail Sales

     1,061,441       1,078,399       (16,958 )   (1.6 )

Tariff-based wholesale

     140,687       138,111       2,576     1.9  

Market-based wholesale

     125,995       100,586       25,409     25.3  

Energy marketing

     31,881       7,049       24,832     352.3  

Transmission (a)

     76,379       76,199       180     0.2  

Other

     24,760       22,807       1,953     8.6  
    


 


 


     

Total Sales

     1,461,143       1,423,151       37,992     2.7  
    


 


 


     

OPERATING EXPENSES:

                              

Fuel used for generation

     342,522       347,377       (4,855 )   (1.4 )

Purchased power

     47,790       32,123       15,667     48.8  

Operating and maintenance

     371,372       379,220       (7,848 )   (2.1 )

Depreciation and amortization

     167,236       171,807       (4,571 )   (2.7 )

Selling, general and administrative

     160,825       218,345       (57,520 )   (26.3 )
    


 


 


     

Total Operating Expenses

     1,089,745       1,148,872       (59,127 )   (5.1 )
    


 


 


     

INCOME FROM OPERATIONS

     371,398       274,279       97,119     35.4  
    


 


 


     

OTHER INCOME (EXPENSE):

                              

Investment earnings

     21,189       30,024       (8,835 )   (29.4 )

ONEOK dividends

     17,316       46,771       (29,455 )   (63.0 )

Gain on sale of ONEOK stock

     99,327       —         99,327     —    

Loss on extinguishment of debt and settlement of putable/callable notes

     (26,455 )     (1,541 )     (24,914 )   (1,616.7 )

Other income

     2,854       1,316       1,538     116.9  

Other expense

     (16,590 )     (38,380 )     21,790     56.8  
    


 


 


     

Total Other Income

     97,641       38,190       59,451     155.7  
    


 


 


     

Interest expense

     224,356       235,172       (10,816 )   (4.6 )
    


 


 


     

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     244,683       77,297       167,386     216.5  

Income tax expense (benefit)

     81,768       (11,519 )     93,287     809.9  
    


 


 


     

INCOME FROM CONTINUING OPERATIONS

     162,915       88,816       74,099     83.4  

Results of discontinued operations, net of tax

     (77,905 )     (881,817 )     803,912     91.2  
    


 


 


     

NET INCOME

     85,010       (793,001 )     878,011     110.7  

Preferred dividends, net of gain on reacquired preferred stock

     968       399       569     142.6  
    


 


 


     

EARNINGS AVAILABLE FOR COMMON STOCK

   $ 84,042     $ (793,400 )   $ 877,442     110.6  
    


 


 


     

EARNINGS PER SHARE

   $ 1.16     $ (11.06 )   $ 12.22     110.5  
    


 


 


     

(a) Transmission: Includes an SPP network transmission tariff. In 2003, our transmission costs were approximately $65.3 million. This amount, less $5.7 million that was retained by the SPP as administration cost, was returned to us as revenues. In 2002, our transmission costs were approximately $65.9 million with an administration cost of $5.7 million retained by the SPP.

 

The following table reflects changes in electric sales volumes, as measured by thousands of MWh of electricity, for the two years ended December 31, 2003 and 2002. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to electricity we generate.

 

     2003

   2002

   Change

    % Change

 
     (Thousands of MWh)        

Residential

   6,031    6,170    (139 )   (2.3 )

Commercial

   6,801    6,817    (16 )   (0.2 )

Industrial

   5,448    5,451    (3 )   (0.1 )

Other retail

   104    106    (2 )   (1.9 )
    
  
  

     

Total retail

   18,384    18,544    (160 )   (0.9 )

Tariff-based wholesale

   4,747    4,905    (158 )   (3.2 )

Market-based wholesale

   3,919    4,210    (291 )   (6.9 )
    
  
  

     

Total

   27,050    27,659    (609 )   (2.2 )
    
  
  

     

 

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Our retail customers used less energy and our sales declined because of cooler weather as well as the sale of a small portion of our rural distribution territory. Commercial and industrial sales revenues showed slight decreases while sales volumes remained relatively flat compared to 2002. The decline in retail sales volumes accounted for approximately $10.2 million of the decline in retail sales revenues. The accrual of approximately $3.5 million to be refunded to customers in 2005 and 2006 pursuant to a KCC order also contributed to the decline in retail sales revenues.

 

The increases in energy marketing and wholesale sales revenues more than offset the decline in retail sales revenues. Higher wholesale market prices were the primary cause of improvement in energy marketing and wholesale sales revenues. The higher wholesale market prices more than offset the decline in wholesale sales volumes.

 

Purchased power expenses increased $15.7 million during 2003. During periods of high energy use in 2003, we purchased more power from other sources than we did during the same periods of 2002 because it was more economical to purchase power than to operate our peaking units. This is also the primary reason our fuel expense decreased.

 

Operating and maintenance expense declined due primarily to the $11.9 million gain recorded in 2003 on the sale of utility assets, which was recorded as an offset to operating expenses. General maintenance expenses at our generating facilities increased by $8.5 million, partially offsetting the decline in operating expenses.

 

Depreciation and amortization expense decreased due to the adoption of new depreciation rates on April 1, 2002.

 

Selling, general and administrative expenses declined in 2003, reflecting a reduction in numerous incremental administrative expenses incurred in 2002. The 2002 administrative expenses included a $36.0 million charge related to a work force reduction, a $9.0 million charge related to an exchange of restricted share units (RSUs) for common stock and an expense of $22.9 million for potential liabilities to Mr. Wittig and Mr. Lake. The decline in selling, general and administrative expenses for 2003 was partially offset by $9.6 million in charges related to the special committee and grand jury investigations in 2003 as compared to charges of $4.7 million in 2002 related to these investigations.

 

Other income improved significantly in 2003 primarily because the mark to market charge to record the fair value of the call option associated with the 6.25% senior unsecured notes that were putable and callable on August 15, 2003 (the putable/callable notes) was $2.2 million for 2003 compared to a charge of $22.6 million for 2002. The smaller mark to market charge in 2003 was the result of the settlement of the call options related to the putable/callable notes in August 2003.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

We believe we will have sufficient cash to fund future operations, debt maturities, the rebates to customers we are required to make in 2005 and 2006, and the payment of dividends from a combination of cash on hand, cash flows from operations and available borrowing capacity. Our available sources of funds include cash, Westar Energy’s revolving credit facility, our accounts receivable conduit facility and access to capital markets. At December 31, 2004, we had cash and cash equivalents of $24.6 million, $284.7 million available under the revolving credit facility and $45.0 million available under the accounts receivable conduit facility. Uncertainties affecting our ability to meet these requirements include, among others, factors affecting sales described in “Operating Results” above, economic conditions, regulatory actions, conditions in the capital markets and compliance with environmental regulations.

 

At December 31, 2004, our total outstanding long-term debt, net of current maturities, was approximately $1.6 billion compared to a balance of approximately $2.1 billion at December 31, 2003. At December 31, 2004, our current maturities of long-term debt were $65.0 million compared to $185.9 million at December 31, 2003.

 

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Capital Resources

 

We had $24.6 million in unrestricted cash and cash equivalents at December 31, 2004. We consider cash equivalents to be highly liquid investments with maturities of three months or less at the time they are purchased.

 

At December 31, 2004, we also had $12.3 million of restricted cash classified as a current asset and $27.4 million of restricted cash classified as a long-term asset, primarily to provide credit security for energy marketing transactions. The following table details our restricted cash at December 31, 2004.

 

     Restricted Cash
Current Portion


   Restricted Cash
Long-term Portion


     (In Thousands)

Prepaid capacity and transmission agreement

   $ 2,256    $ 25,982

Cash held in escrow as required by certain letters of credit, surety bonds and various other deposits

     10,023      1,426
    

  

Total

   $ 12,279    $ 27,408
    

  

 

The Westar Energy mortgage and the KGE mortgage each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. Additionally, Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. Therefore, we must ensure that we will be able to comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

 

The Westar Energy mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless Westar Energy’s unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on, and 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based on the amount of bondable property additions. At December 31, 2004, based on an assumed interest rate of 6%, approximately $210.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings.

 

The KGE mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless KGE’s net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based on the amount of bondable property additions. At December 31, 2004, based on an assumed interest rate of 6%, approximately $874.0 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

 

Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. In June 2004, Westar Energy issued $250.0 million of Westar Energy first mortgage bonds and immediately placed the funds in escrow for retirement of $225.0 million of Westar Energy first mortgage bonds, which was completed in July 2004. Therefore, at December 31, 2004, we could incur a maximum of $275.0 million of additional secured debt under this provision in the Westar Energy revolving credit facility. Following Westar Energy’s January 18, 2005 issuance of $250.0 million of first mortgage bonds, as discussed in “— Debt Financings,” we can incur a maximum of $25.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility.

 

Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million.

 

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Table of Contents

Cash Flows from Operating Activities

 

Cash flows from operating activities increased $203.6 million to $354.2 million in 2004 from $150.6 million for 2003. This increase was primarily attributable to reduced interest of $80.2 million and reduced tax payments of $52.5 million.

 

Cash flows from operating activities decreased $127.5 million to $150.6 million in 2003 from $278.1 million in 2002. This decrease was mostly attributable to taxes paid in 2003 of $53.6 million compared to an income tax refund received in 2002 of $54.1 million, an increase in maintenance expenditures at our generating facilities in 2003 as compared to 2002, and increased legal expenditures in 2003 related to investigations and litigation.

 

Cash Flows (used in) from Investing Activities

 

In general, cash used for investing purposes relates to the growth and improvement of our electric utility business. The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $202.9 million in 2004, $163.5 million in 2003, and $140.4 million in 2002 on net additions to utility property, plant and equipment.

 

In 2004, we received net proceeds of $108.3 million from the sale of Protection One and Protection One bonds. During 2003, we received net proceeds of $801.8 million from the sale of ONEOK stock and net proceeds of $33.3 million from the sale of utility assets. Proceeds from other investments includes ONEOK dividends, proceeds from the sale of investments in affordable housing tax credit limited partnerships and proceeds from the sale of other investments.

 

Cash Flows (used in) Financing Activities

 

Financing activities in 2004 used $323.2 million of cash compared to $881.1 million in 2003. In 2004, we received cash from issuances of long-term debt and the issuance of common stock, and cash was used for the retirement of long-term debt and payment of dividends.

 

We used $881.1 million of cash in 2003 for financing activities compared to $72.4 million in 2002. In 2003, cash was used in financing activities for the retirement of long-term debt and the payment of dividends. In 2003, we reduced our indicated annual dividend from $1.20 per share to $0.76 per share.

 

In 2002, an increase in long-term debt was due primarily to the debt refinancings completed during 2002. These financings were the principal source of cash flows from financing activities used to reduce short-term debt, retire other long-term debt, place funds in a trust to be used for debt repayment, pay dividends, acquire treasury stock and retire a portion of our preferred stock.

 

Future Cash Requirements

 

Our business requires significant capital investments. Through 2007, we expect we will need cash mostly for utility construction programs designed to improve facilities providing electric service and for future peaking capacity needs. In 2006 we anticipate additional cash expenditures necessary to purchase and build approximately 150 MW of peaking generation capacity that we anticipate will be needed in 2008. We expect to meet these cash needs with internally generated cash flow and borrowing under Westar Energy’s revolving credit facility.

 

We are required to pay rebates to retail customers of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. We believe we can fund these rebates with internally generated cash flow and available borrowing capacity under Westar Energy’s revolving credit facility.

 

If we are required to update emissions controls or take other remedial action as a result of the EPA’s investigation, the costs could be material. We may also have to pay fines or penalties or make significant capital or operational expenditures related to the notice of violation we received from the EPA in connection with certain projects completed at Jeffrey Energy Center. In addition, significant capital or operational expenditures may be required in order to comply with future environmental regulations or in connection with future remedial obligations. The following table does not include any amounts related to these possible expenditures. In addition, KCPL, the operator of our jointly owned LaCygne Generating Station, has informed us that it is considering updating or

 

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installing additional equipment related to emissions controls at the LaCygne Generating Station. If KCPL decides to complete this work, we will incur costs beginning in 2005 and continuing through the completion of installation in 2007. We expect that costs related to updating or installing emissions controls will be material. These costs are not included in the following table. We believe that these costs would qualify for recovery through rates.

 

Capital expenditures for 2004 and anticipated capital expenditures for 2005 through 2007, including costs of removal, are shown in the following table.

 

    

Actual

2004


   2005

   2006

   2007

     (In Thousands)

Replacements and other

   $ 138,376    $ 151,600    $ 152,600    $ 168,200

Additional capacity

     5,513      7,700      17,300      42,100

New customer construction

     38,038      45,700      64,300      49,500

Nuclear fuel

     20,965      4,900      19,300      24,000
    

  

  

  

Total capital expenditures

   $ 202,892    $ 209,900    $ 253,500    $ 283,800
    

  

  

  

 

We prepare these estimates for planning purposes and revise our estimates from time to time. Actual expenditures will differ from our estimates. These amounts do not include any estimate of expenditures that may be incurred as a result of the EPA investigation or other enacted or proposed environmental regulations. Environmental expenditures could be material.

 

Maturities of long-term debt at December 31, 2004 are as follows.

 

Year


   Principal Amount

   (In Thousands)

2005

   $ 65,000

2006

     100,000

2007

     625,000

2008

     —  

2009

     145,078

Thereafter

     769,823
    

     $ 1,704,901
    

 

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Debt Financings

 

During 2004, we made changes in our long-term debt as shown in the table below.

 

     Balance as of
December 31,
2003


   Securities
Redeemed


    Securities
Issued


   Balance as of
December 31,
2004


     (In Thousands)

Long-term Debt Redemptions and Issuances:

                            

Westar Energy

                            

First mortgage bond series:

                            

6.00% due 2014

   $ —      $ —       $ 250,000    $ 250,000

8.5% due 2022

     125,000      (125,000 )     —        —  

7.65% due 2023

     100,000      (100,000 )     —        —  

Pollution control bond series:

                            

6.00% due 2033

     58,340      (58,340 )     —        —  

5.00% due 2033

     —        —         58,340      58,340

6 7/8% senior unsecured notes due August 1, 2004

     184,456      (184,456 )     —        —  

9 3/4% senior unsecured notes due 2007

     387,000      (127,000 )     —        260,000

6.80% senior unsecured notes due 2018

     26,993      (26,993 )     —        —  

Senior secured term loan due 2005

     114,143      (114,143 )     —        —  
    

  


 

  

     $ 995,932    $ (735,932 )   $ 308,340    $ 568,340
    

  


 

  

KGE

                            

Pollution control bond series:

                            

7.00% due 2031

   $ 327,500    $ (327,500 )   $ —      $ —  

5.30% due 2031

     —        —         108,600      108,600

5.30% due 2031

     —        —         18,900      18,900

2.65% due 2031 and putable 2006

     —        —         100,000      100,000

Variable rate due 2031

     —        —         100,000      100,000
    

  


 

  

     $ 327,500    $ (327,500 )   $ 327,500    $ 327,500
    

  


 

  

Long-term debt affiliate

   $ 103,093    $ (103,093 )   $ —      $ —  
    

  


 

  

 

On March 12, 2004, Westar Energy entered into a revolving credit facility. The credit facility matures on March 12, 2007. It is used as a source of short-term liquidity. It allows us borrowings up to an aggregate limit of $300.0 million, including letters of credit up to a maximum aggregate amount of $50.0 million. At December 31, 2004, we had no outstanding borrowings and $15.3 million of letters of credit outstanding under the revolving credit facility. All borrowings under the revolving credit facility are secured by KGE first mortgage bonds.

 

On January 18, 2005, Westar Energy sold $250.0 million aggregate principal amount of Westar Energy first mortgage bonds, consisting of $125.0 million 5.15% bonds maturing in 2017 and $125.0 million 5.95% bonds maturing in 2035. On February 17, 2005, we used the net proceeds from the offering, together with cash on hand, additional funds raised through the accounts receivable conduit facility and borrowings under Westar Energy’s revolving credit facility, to redeem the remaining $260.0 million aggregate principal amount of Westar Energy 9.75% senior notes due 2007. Together with accrued interest and a premium equal to approximately 12% of the outstanding senior notes, we paid $298.5 million to redeem the Westar Energy 9.75% senior notes due 2007. After this transaction, we had $10.0 million outstanding under the revolving credit facility and $30.0 million available under the accounts receivable conduit facility.

 

Debt Covenants

 

Some of our debt instruments contain restrictions that require us to maintain various coverage and leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. These ratios are used solely to determine compliance with our various debt covenants. We were in compliance with these covenants at December 31, 2004.

 

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Table of Contents

Interest Rate Swap

 

Effective October 4, 2001, we entered into a $500.0 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on a term loan at 6.18%. We settled the swap agreement for a nominal amount on September 29, 2003. For information regarding ongoing interest rates, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

 

Credit Ratings

 

Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service (Moody’s) and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our securities.

 

On February 23, 2005, Moody’s upgraded its ratings for our debt and affirmed the speculative liquidity rating it assigned to us of SGL-2, reflecting its view that we have “good” liquidity. On December 22, 2004, Fitch raised its outlook rating to positive from stable and affirmed its ratings as shown in the table below. On July 22, 2004, S&P improved its ratings on KGE’s first mortgage bonds to BBB from BB+.

 

As of March 1, 2005, ratings with these agencies are as shown in the table below.

 

     Westar
Energy
Mortgage
Bond
Rating


   Westar
Energy
Unsecured
Debt


  

KGE

Mortgage

Bond

Rating


S&P

   BBB-    BB-    BBB

Moody’s

   Baa3    Ba1    Baa3

Fitch

   BBB-    BB+    BBB-

 

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us. Westar Energy and KGE have credit rating conditions under our revolving credit agreement and in the agreements governing the sale of our accounts receivable discussed in Note 5 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities” that affect the cost of borrowing but do not trigger a default. We may enter into new credit agreements that contain credit conditions, which could affect our liquidity and/or our borrowing costs.

 

Capital Structure

 

Our consolidated capital structure at December 31, 2004 and 2003 was as follows.

 

     2004

    2003

 

Common equity

   45 %   31 %

Preferred stock

   1 %   1 %

Debt

   54 %   68 %
    

 

Total

   100 %   100 %
    

 

 

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Table of Contents

OFF-BALANCE SHEET ARRANGEMENTS

 

Accounts Receivable Sales Program

 

Under a revolving accounts receivable sales program, we currently sell up to $125.0 million of our accounts receivable. For additional detail, see Note 5 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities.”

 

LaCygne 2 Sale/Leaseback Agreement

 

In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operating and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the lease term. See Note 23 of the Notes to Consolidated Financial Statements, “Leases,” for additional information.

 

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

 

In the course of our business activities, we enter into a variety of contractual obligations and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements. The obligations listed below do not include amounts for on-going needs for which no contractual obligations existed at December 31, 2004, and represent only those amounts that we were contractually obligated to meet at December 31, 2004. We may from time to time enter into new contracts to replace contracts that expire.

 

Contractual Cash Obligations

 

The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2004.

 

     Total

   2005 (c)

   2006 (c) - 2007

   2008 – 2009

   Thereafter

     (In Thousands)

Long-term debt (a)

   $ 1,704,901    $ 65,000    $ 725,000    $ 145,078    $ 769,823

Interest payments on long-term debt (b)

     846,537      107,087      199,523      85,136      454,791
    

  

  

  

  

Adjusted long-term debt

     2,551,438      172,087      924,523      230,214      1,224,614

Capital leases (d)

     24,201      5,267      8,569      5,903      4,462

Operating leases (e)

     613,898      49,422      140,041      69,145      355,290

Fossil fuel (f)

     1,569,155      188,304      339,237      295,529      746,085

Nuclear fuel (g)

     162,691      4,404      39,898      12,649      105,740

Unconditional purchase obligations

     34,612      28,601      6,011      —        —  

Miscellaneous obligations

     2,032      816      1,216      —        —  
    

  

  

  

  

Total contractual obligations, including adjusted long-term debt

   $ 4,958,027    $ 448,901    $ 1,459,495    $ 613,440    $ 2,436,191
    

  

  

  

  


(a) See Note 11 of the Notes to Consolidated Financial Statements, “Long-term Debt,” for individual long-term debt maturities.
(b) We calculate interest payments on our variable rate debt based on the effective interest rate at December 31, 2004.
(c) We have an obligation to pay rebates to customers in 2005 and 2006.
(d) Includes principal and interest on capital leases.
(e) Includes the LaCygne 2 lease, office space, operating facilities, office equipment, operating equipment and other miscellaneous commitments.
(f) Coal and natural gas commodity and transportation contracts.
(g) Uranium concentrates, conversion, enrichment, fabrication and spent fuel disposal.

 

Commercial Commitments

 

Our commercial commitments existing at December 31, 2004 are outstanding letters of credit that expire in 2005. The letters of credit are comprised of $6.6 million related to our energy marketing and trading activities, $5.2 million related to worker’s compensation and $4.5 million related to other operating activities for a total outstanding balance of $16.3 million.

 

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Table of Contents

OTHER INFORMATION

 

Ice Storm

 

On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric service in a large portion of our service territory and damaged a significant portion of our electric distribution system. We estimate that we will incur $38.0 million to $42.0 million of system restoration costs. Of this amount, we expect $6.0 million to $8.0 million to be accounted for as capital expenditures and we expect the balance related to maintenance expenditures to be accounted for as a regulatory asset. On February 3, 2005, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery maintenance costs related to system restoration. We can provide no assurance that the KCC will approve our application, however, in the past the KCC has approved similar requests.

 

New Accounting Pronouncements

 

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment: An Amendment of FASB Statements No. 123 and 95.” SFAS No. 123R requires companies to recognize as compensation expense the grant-date fair value of stock options and other equity-based compensation issued to employees. The provisions of the statement are effective for financial statements issued for periods that begin after June 15, 2005, which will be our third quarter beginning July 1, 2005.

 

We currently use RSUs for stock-based awards granted to employees. In addition, we have eliminated our employee stock purchase plan and all outstanding options have vested. Given the characteristics of our stock-based compensation program, we do not expect the adoption of SFAS No. 123R to materially impact our results of operations.

 

Sale of Utility Assets

 

In August 2003, we sold a portion of our transmission and distribution assets and rights to provide service to approximately 10,000 customers in an area of central Kansas. Total sales proceeds received were $33.3 million and we realized a gain of $11.9 million. We may enter into similar transactions in the future.

 

Impact of Regulatory Accounting

 

We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our electric utility operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings.

 

At December 31, 2004, we had recorded regulatory assets currently subject to recovery in future rates of approximately $442.9 million. Of this amount, $191.6 million is related to income tax benefits previously passed on to customers. The remainder of the regulatory assets include asset retirement obligations, system restoration, loss on reacquired debt, refinancing costs on the LaCygne 2 lease, deferred employee benefit costs, deferred plant costs and coal contract settlement costs. We periodically review SFAS No. 71 criteria and believe that our net regulatory assets are probable of future recovery.

 

Asset Retirement Obligations

 

In January 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Any income effects are offset by regulatory accounting pursuant to SFAS No. 71.

 

Legal Liability - Wolf Creek

 

On January 1, 2003, we recognized the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the present value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset

 

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retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. We also established a regulatory asset for $64.0 million, which represents the accretion of the liability since 1985 and the increased depreciation expense associated with the increase in plant. The asset retirement obligation is included on our consolidated balance sheets in other long-term liabilities. Costs to retire Wolf Creek are currently being recovered through rates as provided by the KCC.

 

Non-legal Liability - Cost of Removal

 

We have recovered amounts in rates to provide for recovery of the probable costs of removing utility plant assets, but which do not represent legal retirement obligations. At December 31, 2004, Westar Energy had $1.3 million in removal costs classified as a regulatory asset and KGE had $2.6 million in removal costs classified as a regulatory liability. At December 31, 2003, we had $6.6 million in removal costs classified as a regulatory asset. The net amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to removal costs incurred.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Hedging Activity

 

We use financial and physical instruments to economically hedge the price of a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine what the value will be when the agreements are actually settled.

 

In an effort to mitigate market risk associated with fuel and energy prices, we may use economic hedging arrangements to reduce our exposure to price increases. Our future exposure to changes in prices will be dependent on the market prices and the extent and effectiveness of any economic hedging arrangements into which we enter.

 

See Note 6 of the Notes to Consolidated Financial Statements, “Financial Instruments, Energy Marketing and Risk Management — Derivative Instruments and Hedge Accounting — Hedging Activities,” for detailed information regarding hedging relationships and an interest rate swap we entered into during the third quarter of 2001.

 

Market Price Risks

 

Our economic hedging and trading activities involve risks, including commodity price risk, interest rate risk and credit risk. Commodity price risk is the risk that changes in commodity prices may impact the price at which we are able to buy and sell electricity and purchase fuels for our generating units. We believe we will continue to experience volatility in the prices for these commodities. This volatility may increase or decrease future earnings.

 

Interest rate risk represents the risk of loss associated with movements in market interest rates. In the future, we may use swaps or other financial instruments to manage interest rate risk.

 

Credit risk represents the risk of loss resulting from non-performance by a counterparty of its contractual obligations. We have exposure to credit risk and counterparty default risk with our retail, wholesale and energy marketing activities. We maintain credit policies intended to reduce overall credit risk. We employ additional credit risk control mechanisms that we believe are appropriate, such as letters of credit, parental guarantees and master netting agreements with counterparties that allow for offsetting exposures. Results actually achieved from economic hedging and trading activities could vary materially from intended results and could materially affect our consolidated financial results depending on the success of our credit risk management efforts.

 

Commodity Price Exposure

 

We engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil. We use financial instruments, including forward contracts, options and swaps and we trade energy commodity contracts daily. We may also use economic hedging techniques to manage overall fuel expenditures. We procure physical product under forward agreements and spot market transactions.

 

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We are involved in trading activities to reduce risk from market fluctuations, enhance system reliability and increase profits. Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations.

 

We manage and measure the market price risk exposure of our trading portfolio using a variance/covariance value-at-risk (VaR) model. The VaR model is designed to measure the predicted maximum one-day loss at a 95% confidence level. In addition to VaR, we employ additional risk control processes such as stress testing, daily loss limits, credit limits and position limits. We expect to use similar control processes in 2005.

 

The use of the VaR method requires assumptions, including the selection of a confidence level for potential losses and the estimated holding period. This means that we are also exposed to the risk that we value and mark illiquid prices incorrectly. We express VaR as a potential dollar loss based on a 95% confidence level using a one-day holding period. The calculation includes derivative commodity instruments used for both trading and risk management purposes. The VaR amounts for 2004 and 2003 were as follows.

 

     2004

   2003

     (In Thousands)

High

   $ 2,891    $ 1,393

Low

     713      144

Average

     1,321      722

 

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that we believe are effective in managing overall credit risk. There can be no assurance that the employment of VaR, or other risk management tools we employ, will eliminate the risk of loss.

 

We are also exposed to commodity price changes outside of trading activities. We use derivative contracts for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

 

From 2003 to 2004, we experienced an approximate 6% increase in the average price per MWh of electricity purchased for utility operations. Volatility in the prices for power we purchase could be greater than the average price increase indicates. Additionally, short-term, but extreme price volatility could potentially be of greater significance than the change in the average price would indicate, especially during adverse weather or market conditions. If we were to have a 10% increase in our purchased power price from 2004 to 2005, given the amount of power purchased for utility operations during 2004, we would have exposure of approximately $4.7 million of operating income. Due to the volatility of the power market, we believe past prices are not a good predictor of future prices.

 

We use various fossil fuel types, including coal, natural gas and oil, to operate our plants. A significant portion of our coal requirements are purchased under long-term contracts. During 2004, we experienced an approximate 37% increase, or $1.79 per MMBtu, in our average cost for natural gas purchased for utility operations. Due to the volatility of natural gas prices, we have increasingly operated facilities that have allowed us to use lower cost fuel types as generating unit constraints and environmental restrictions allow, primarily by using oil in our facilities that also burn natural gas. The average cost for oil purchased for utility operations increased $0.53 per MMBtu, or approximately 16%, compared to the average cost in 2003. The average cost of oil burned was $2.85 per MMBtu less than the average cost of the natural gas we burned. If we were to have a 10% increase in our price for natural gas and oil burned from 2004 to 2005, based on MMBtus of natural gas and oil burned during 2004, we would have exposure of approximately $6.7 million of operating income. Due to the volatility of natural gas prices, past prices cannot be used to predict future prices.

 

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We have 100% of the uranium and conversion services required to operate Wolf Creek under contract through September 2009. We also have 100% of the enrichment services required to operate Wolf Creek under contract through March 2008. We will be exposed to the price risk associated with any components not currently under contract if a counterparty were to fail its contractual obligations.

 

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and scheduled outages at our facilities that use fossil fuels and the nuclear refueling schedule. Our customers’ electricity usage could also vary from year to year based on the weather or other factors.

 

Interest Rate Exposure

 

We had approximately $286.9 million of variable rate debt and current maturities of fixed rate debt at December 31, 2004. A 100 basis point change in interest rates applicable to this debt would impact operating income on an annualized basis by approximately $2.8 million.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

TABLE OF CONTENTS

 

     PAGE

Management’s Report on Internal Control Over Financial Reporting

   41

Reports of Independent Registered Public Accounting Firm

   42

Financial Statements:

    

Westar Energy, Inc. and Subsidiaries:

    

Consolidated Balance Sheets, as of December 31, 2004 and 2003

   44

Consolidated Statements of Income (Loss) for the years ended December 31, 2004, 2003 and 2002

   45

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002

   46

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

   47

Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2004, 2003 and 2002

   48

Notes to Consolidated Financial Statements

   49

Financial Schedules:

    

Schedule II - Valuation and Qualifying Accounts

   99

 

SCHEDULES OMITTED

 

The following schedules are omitted because of the absence of the conditions under which they are required or the information is included on our consolidated financial statements and schedules presented:

 

I, III, IV, and V.

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

We are responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

 

    Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

 

    Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

 

    Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

We assessed the effectiveness of our internal control over financial reporting at December 31, 2004. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on the assessment, we believe that, at December 31, 2004, our internal control over financial reporting is effective based on those criteria. Our independent registered public accounting firm has issued an audit report on our assessment of our internal control over financial reporting.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and

Shareholders of Westar Energy, Inc.

Topeka, Kansas

 

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Controls over Financial Reporting, that Westar Energy, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our report dated March 11, 2005 expressed an unqualified opinion on those financial statements and financial statement schedule.

 

DELOITTE & TOUCHE LLP

 

Kansas City, Missouri

March 11, 2005

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and

Shareholders of Westar Energy, Inc.

Topeka, Kansas

 

We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

 

As discussed in Note 16 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations.”

 

As discussed in Note 5 to the consolidated financial statements, effective October 1, 2003, the Company adopted FIN 46R, “Consolidation of Variable Interest Entities.”

 

As discussed in Note 4 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets,” and Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

DELOITTE & TOUCHE LLP

 

Kansas City, Missouri

March 11, 2005

 

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WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

 

     As of December 31,

 
     2004

    2003

 
ASSETS                 

CURRENT ASSETS:

                

Cash and cash equivalents

   $ 24,611     $ 79,559  

Restricted cash

     12,279       17,925  

Accounts receivable, net

     92,532       80,971  

Inventories and supplies

     124,563       134,931  

Energy marketing contracts

     23,155       35,385  

Tax receivable

     90,845       5,961  

Deferred tax assets

     7,218       123,256  

Prepaid expenses

     29,179       32,430  

Other

     11,558       10,747  

Assets of discontinued operations

     —         570,541  
    


 


Total Current Assets

     415,940       1,091,706  
    


 


PROPERTY, PLANT AND EQUIPMENT, NET

     3,910,987       3,909,500  
    


 


OTHER ASSETS:

                

Restricted cash

     27,408       31,854  

Regulatory assets

     442,944       411,315  

Nuclear decommissioning trust

     91,095       80,075  

Energy marketing contracts

     4,904       4,190  

Other

     192,433       214,335  
    


 


Total Other Assets

     758,784       741,769  
    


 


TOTAL ASSETS

   $ 5,085,711     $ 5,742,975  
    


 


LIABILITIES AND SHAREHOLDERS’ EQUITY                 

CURRENT LIABILITIES:

                

Current maturities of long-term debt

   $ 65,000     $ 185,941  

Short-term debt

     —         1,000  

Accounts payable

     105,593       92,994  

Accrued taxes

     97,874       108,249  

Energy marketing contracts

     20,431       28,000  

Accrued interest

     30,506       33,651  

Other

     99,170       85,904  

Liabilities of discontinued operations

     —         475,597  
    


 


Total Current Liabilities

     418,574       1,011,336  
    


 


LONG-TERM LIABILITIES:

                

Long-term debt, net

     1,639,901       1,948,253  

Long-term debt, affiliate

     —         103,093  

Unamortized investment tax credits

     68,957       74,291  

Deferred income taxes

     927,087       969,544  

Deferred gain from sale-leaseback

     138,981       150,810  

Accrued employee benefits

     120,152       121,308  

Asset retirement obligation

     87,118       80,695  

Nuclear decommissioning

     91,095       80,075  

Energy marketing contracts

     1,547       1,111  

Other

     182,977       165,699  
    


 


Total Long-Term Liabilities

     3,257,815       3,694,879  
    


 


COMMITMENTS AND CONTINGENCIES (see Notes 15 and 17)

                

SHAREHOLDERS’ EQUITY:

                

Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares

     21,436       21,436  

Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,029,721 shares and 72,840,217 shares, respectively

     430,149       364,201  

Paid-in capital

     912,932       776,754  

Unearned compensation

     (10,361 )     (15,879 )

Loans to officers

     —         (2 )

Retained earnings (accumulated deficit)

     55,053       (102,782 )

Treasury stock, at cost, 0 and 203,575 shares, respectively

     —         (2,391 )

Accumulated other comprehensive income (loss), net

     113       (4,577 )
    


 


Total Shareholders’ Equity

     1,409,322       1,036,760  
    


 


TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 5,085,711     $ 5,742,975  
    


 


 

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Dollars in Thousands, Except Per Share Amounts)

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

SALES

   $ 1,464,489     $ 1,461,143     $ 1,423,151  
    


 


 


OPERATING EXPENSES:

                        

Fuel and purchased power

     419,788       390,312       379,500  

Operating and maintenance

     412,002       371,372       379,220  

Depreciation and amortization

     169,310       167,236       171,807  

Selling, general and administrative

     173,498       160,825       218,345  
    


 


 


Total Operating Expenses

     1,174,598       1,089,745       1,148,872  
    


 


 


INCOME FROM OPERATIONS

     289,891       371,398       274,279  
    


 


 


OTHER INCOME (EXPENSE):

                        

Investment earnings

     16,746       38,505       76,795  

Gain on sale of ONEOK stock

     —         99,327       —    

Loss on extinguishment of debt and settlement of putable/callable notes

     (18,840 )     (26,455 )     (1,541 )

Other income

     2,756       2,854       1,316  

Other expense

     (14,879 )     (16,590 )     (38,380 )
    


 


 


Total Other Income (Expense)

     (14,217 )     97,641       38,190  
    


 


 


Interest expense

     142,151       224,356       235,172  
    


 


 


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     133,523       244,683       77,297  

Income tax expense (benefit)

     33,443       81,768       (11,519 )
    


 


 


INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     100,080       162,915       88,816  
    


 


 


Results of discontinued operations, net of tax

                        

Discontinued operations, net of tax

     78,790       (77,905 )     (258,100 )

Cumulative effect of accounting change, net of tax

     —         —         (623,717 )
    


 


 


Results of discontinued operations, net of tax

     78,790       (77,905 )     (881,817 )

NET INCOME (LOSS)

     178,870       85,010       (793,001 )

Preferred dividends, net of gain on reacquired preferred stock

     970       968       399  
    


 


 


EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK

   $ 177,900     $ 84,042     $ (793,400 )
    


 


 


BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):

                        

Basic earnings available from continuing operations before accounting change

   $ 1.19     $ 2.24     $ 1.23  

Discontinued operations, net of tax

     0.95       (1.08 )     (3.60 )

Accounting change, including discontinued operations, net of tax

     —         —         (8.69 )
    


 


 


Basic earnings (loss) available

   $ 2.14     $ 1.16     $ (11.06 )
    


 


 


Diluted earnings available from continuing operations before accounting change

   $ 1.19     $ 2.20     $ 1.22  

Discontinued operations, net of tax

     0.94       (1.06 )     (3.57 )

Accounting change, including discontinued operations, net of tax

     —         —         (8.63 )
    


 


 


Diluted earnings (loss) available

   $ 2.13     $ 1.14     $ (10.98 )
    


 


 


Average equivalent common shares outstanding

     82,941,374       72,428,728       71,731,580  

DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.80     $ 0.76     $ 1.20  

 

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

NET INCOME (LOSS)

          $ 178,870             $ 85,010            $ (793,001 )
           


         


        


OTHER COMPREHENSIVE INCOME:

                                              

Unrealized holding gain on marketable securities arising during the period

   $ 11            $ 99,412             $ —           

Reclassification adjustment for gain included in net income

     —        11       (99,310 )     102       —        —    
    

          


         

        

Unrealized holding gain on cash flow hedges arising during the period

     —                12,270               19,466         

Reclassification adjustment for (gain) loss included in net income

     —        —         (4,543 )     7,727       1,992      21,458  
    

  


 


         

        

Minimum pension liability adjustment

            7,769               284              (1,341 )

Foreign currency translation adjustment

            —                 —                1,044  
           


         


        


Other comprehensive income, before tax

            7,780               8,113              21,161  

Income tax expense related to items of other comprehensive income

            (3,090 )             (3,188 )            (8,032 )
           


         


        


Other comprehensive gain, net of tax

            4,690               4,925              13,129  
           


         


        


COMPREHENSIVE INCOME (LOSS)

          $ 183,560             $ 89,935            $ (779,872 )
           


         


        


 

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

                        

Net income (loss)

   $ 178,870     $ 85,010     $ (793,001 )

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                        

Discontinued operations, net of tax

     (78,790 )     77,905       881,817  

Depreciation and amortization

     169,310       167,236       171,807  

Amortization of nuclear fuel

     14,221       12,410       13,142  

Amortization of deferred gain from sale-leaseback

     (11,828 )     (11,828 )     (11,828 )

Amortization of prepaid corporate-owned life insurance

     12,622       14,320       20,321  

Non-cash stock compensation

     7,916       6,885       14,006  

Net changes in energy marketing assets and liabilities

     4,383       (1,855 )     20,229  

Loss on extinguishment of debt and settlement of putable/callable notes

     18,840       26,455       1,541  

Net changes in fair value of call option

     —         2,178       22,609  

Equity in earnings from investments

     —         —         (9,670 )

Gain on sale of ONEOK stock

     —         (99,327 )     —    

Accrued liability to certain former officers

     8,384       1,205       22,928  

(Gain) loss on sale of utility plant and property

     (503 )     (11,912 )     1,424  

Net deferred income taxes and credits

     (5,215 )     (100,275 )     35,111  

Changes in working capital items, net of acquisitions and dispositions:

                        

Restricted cash

     7,825       (4,794 )     (6,596 )

Accounts receivable, net

     (11,561 )     (32,031 )     (4,534 )

Inventories and supplies

     10,368       8,607       (8,955 )

Prepaid expenses and other

     (40,557 )     16,897       (49,079 )

Accounts payable

     12,182       6,231       (21,396 )

Accrued taxes

     43,463       81,135       (7,834 )

Other current liabilities

     (5,046 )     (84,021 )     (13,339 )

Changes in other, assets

     10,566       2,451       (30,869 )

Changes in other, liabilities

     8,738       (12,245 )     30,247  
    


 


 


Cash flows from operating activities

     354,188       150,637       278,081  
    


 


 


CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

                        

Additions to property, plant and equipment

     (188,447 )     (150,378 )     (126,763 )

Removal, dismantlement and salvage of property, plant and equipment

     (14,445 )     (13,094 )     (13,621 )

Investment in corporate-owned life insurance

     (19,658 )     (19,599 )     (19,399 )

Proceeds from investment in corporate-owned life insurance

     —         —         7,859  

Proceeds from sale of Protection One

     81,670       —         —    

Proceeds from sale of Protection One bonds

     26,640       —         —    

Proceeds from sale of plant and property

     8,604       33,303       1,205  

Proceeds from sale of international investment

     11,219       —         —    

Proceeds from sale of ONEOK stock

     —         801,841       —    

Issuance of officer loans and interest, net of payments

     2       438       (308 )

Proceeds from other investments

     9,591       801       18,296  
    


 


 


Cash flows (used in) from investing activities

     (84,824 )     653,312       (132,731 )
    


 


 


CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

                        

Short-term debt, net

     (1,000 )     —         (221,300 )

Proceeds from long-term debt

     623,301       —         1,350,069  

Retirements of long-term debt

     (1,188,081 )     (963,330 )     (1,021,993 )

Funds in trust for debt repayments

     78       145,182       (135,000 )

Purchase of call option investment

     —         (65,785 )     —    

Repayment of capital leases

     (4,977 )     (5,138 )     (5,019 )

Borrowings against cash surrender value of corporate-owned life insurance

     57,090       58,818       61,120  

Repayment of borrowings against cash surrender value of corporate-owned life insurance

     (444 )     (419 )     (8,490 )

Issuance of common stock, net

     245,130       —         2,551  

Cash dividends paid

     (56,189 )     (57,726 )     (73,535 )

Retirement of preferred stock

     —         —         (1,547 )

Acquisition of treasury stock

     —         —         (19,544 )

Reissuance of treasury stock

     1,927       7,260       255  
    


 


 


Cash flows (used in) financing activities

     (323,165 )     (881,138 )     (72,433 )
    


 


 


Net cash (used in) from discontinued operations

     (1,147 )     43,699       (48,059 )
    


 


 


Foreign currency translation

     —         —         1,044  
    


 


 


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

     (54,948 )     (33,490 )     25,902  

CASH AND CASH EQUIVALENTS:

                        

Beginning of period

     79,559       113,049       87,147  
    


 


 


End of period

   $ 24,611     $ 79,559     $ 113,049  
    


 


 


 

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands)

 

     Year Ended December 31,

 
     2004

    2003

    2002

 
     Shares

    Amount

    Shares

    Amount

    Shares

    Amount

 

Cumulative preferred stock:

                                          

Beginning balance

   214,363     $ 21,436     214,363     $ 21,436     239,364     $ 23,936  

Retirement of preferred stock

   —         —       —         —       (25,001 )     (2,500 )
    

 


 

 


 

 


Ending balance

   214,363       21,436     214,363       21,436     214,363       21,436  
    

 


 

 


 

 


Common stock:

                                          

Beginning balance

   72,840,217       364,201     72,840,217       364,201     86,205,417       431,027  

Issuance of common stock

   13,189,504       65,948     —         —       6,936,289       34,681  

Retirement of common stock

   —         —       —         —       (20,301,489 )     (101,507 )
    

 


 

 


 

 


Ending balance

   86,029,721       430,149     72,840,217       364,201     72,840,217       364,201  
    

 


 

 


 

 


Paid-in capital:

                                          

Beginning balance

           776,754             825,744             1,196,765  

Preferred dividends, net of retirements

           653             728             (1,035 )

Issuance of common stock, net

           192,337             —               76,586  

Dividends on common stock

           (46,473 )           (53,501 )           (87,088 )

Retirement of common stock

           —               —               (349,397 )

Issuance of treasury stock

           1,230             671             2  

Grant of restricted stock

           1,417             7,631             7,872  

Stock compensation

           (12,986 )           (4,519 )           (17,961 )
          


       


       


Ending balance

           912,932             776,754             825,744  
          


       


       


Unearned compensation:

                                          

Beginning balance

           (15,879 )           (14,742 )           (21,920 )

Grant of restricted stock

           (1,417 )           (7,631 )           (7,872 )

Amortization of restricted stock

           6,838             6,494             8,647  

Forfeited restricted stock

           97             —               6,403  
          


       


       


Ending balance

           (10,361 )           (15,879 )           (14,742 )
          


       


       


Loans to officers:

                                          

Beginning balance

           (2 )           (1,832 )           (1,973 )

Issuance of officer loans and interest, net of payments

           2             438             (309 )

Reclass loans of former officers to other assets

           —               1,392             450  
          


       


       


Ending balance

           —               (2 )           (1,832 )
          


       


       


Retained earnings (accumulated deficit):

                                          

Beginning balance

           (102,782 )           (185,961 )           606,502  

Net income (loss)

           178,870             85,010             (793,001 )

Preferred dividends, net of retirements

           (1,074 )           (1,696 )           597  

Dividends on common stock

           (19,786 )           —               —    

Issuance of treasury stock

           (175 )           (135 )           (59 )
          


       


       


Ending balance

           55,053             (102,782 )           (185,961 )
          


       


       


Treasury stock:

                                          

Beginning balance

   (203,575 )     (2,391 )   (1,333,264 )     (18,704 )   (15,097,987 )     (364,901 )

Issuance of common stock

   —         —       —         —       (5,253,502 )     (86,869 )

Retirement of common stock

   —         —       —         —       20,301,489       450,904  

Acquisition of treasury stock

   —         —       —         —       (1,434,100 )     (19,508 )

Issuance of treasury stock

   203,575       2,391     1,129,689       16,313     150,836       1,670  
    

 


 

 


 

 


Ending balance

   —         —       (203,575 )     (2,391 )   (1,333,264 )     (18,704 )
    

 


 

 


 

 


Accumulated other comprehensive income (loss):

                                          

Beginning balance

           (4,577 )           (9,502 )           (22,631 )

Unrealized gain on marketable securities

           11             102             —    

Unrealized gain on cash flow hedges

           —               7,727             21,458  

Minimum pension liability adjustment

           7,769             284             (1,341 )

Foreign currency translation adjustment

           —               —               1,044  

Income tax expense

           (3,090 )           (3,188 )           (8,032 )
          


       


       


Ending balance

           113             (4,577 )           (9,502 )
          


       


       


Total Shareholders’ Equity

         $ 1,409,322           $ 1,036,760           $ 980,640  
          


       


       


 

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

 

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WESTAR ENERGY, INC.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. DESCRIPTION OF BUSINESS

 

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 653,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

 

KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas, and a 47% interest in Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Principles of Consolidation

 

We prepare our consolidated financial statements in accordance with Generally Accepted Accounting Principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions and majority owned subsidiaries for which we maintain controlling interests. Common stock investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation.

 

Use of Management’s Estimates

 

When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, investments, valuation of our energy marketing portfolio, intangible assets, income taxes, pension and other post-retirement and post-employment benefits, our asset retirement obligations including decommissioning of Wolf Creek, net amount of tax benefits realizable from the disposition of our monitored security businesses, environmental issues, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

 

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Regulatory Accounting

 

We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

 

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent probable obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.

 

     As of December 31,

     2004

   2003

     (In Thousands)

Amounts due from customers for future income taxes, net

   $ 191,597    $ 207,812

Debt reacquisition costs

     45,203      25,155

Deferred employee benefit costs

     39,727      18,424

Deferred plant costs

     27,979      28,532

2002 ice storm costs

     17,774      16,369

Asset retirement obligations

     77,349      70,455

KCC depreciation

     22,596      14,294

Wolf Creek outage

     6,467      13,645

Other regulatory assets

     14,252      16,629
    

  

Total regulatory assets

   $ 442,944    $ 411,315
    

  

Total regulatory liabilities

   $ 29,292    $ 14,323
    

  

 

•        Amounts due from customers for future income taxes, net: In accordance with various rate orders, we have reduced rates to reflect the tax benefits associated with certain accelerated tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce rates charged customers for deferred taxes recovered from customers at corporate tax rates higher than the current tax rates. The rate reduction will occur as the temporary differences resulting in the excess deferred tax liabilities reverse. The tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled through future rates. The net regulatory asset for these tax items is classified above as amounts due from customers for future income taxes.

 

•        Debt reacquisition costs: Includes loss on reacquired debt and refinancing costs on the LaCygne 2 generating unit lease. Debt reacquisition costs are amortized over the original term of the reacquired debt or, if refinanced, the term of the new debt.

 

•        Deferred employee benefit costs: Employee benefit costs include pension benefit obligations and post-retirement and post-employment expenses.

 

•        Deferred plant costs: Deferred plant costs under SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs,” related to the Wolf Creek nuclear generating facility will be recovered over the term of the plant’s operating license through 2025.

 

•        2002 ice storm costs: We accumulated and deferred for future recovery costs related to system restoration from an ice storm that occurred in January 2002. We were authorized to accrue carrying costs on this item. Recovery of this asset will be considered during the 2005 rate review.

 

•        Asset retirement obligations: Asset retirement obligations represent amounts associated with our legal obligation to retire Wolf Creek. We recover final retirement costs through rates as provided by the Kansas Corporation Commission (KCC). We have placed amounts recovered through rates in a trust. The trust’s funds will be used to pay for the costs to retire and decommission Wolf Creek. See Note 16, “Asset Retirement Obligations,” for information regarding our Nuclear Decommissioning Trust Fund.

 

 

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        KCC depreciation: Due to the change in our depreciation rates for ratemaking purposes for Wolf Creek and LaCygne 2, we record a regulatory asset for the amount that our depreciation expense exceeds our depreciation costs recovered in rates. See “—Depreciation” for additional information.

 

•        Wolf Creek outage: Represents maintenance costs incurred in our most recent refueling outage. In accordance with regulatory treatment, this amount is amortized to expense ratably over the 18-month period after the outage.

 

•        Other regulatory assets: This includes various regulatory assets that are relatively small in relation to the total regulatory assets balance. Other regulatory assets include property taxes, coal contract settlement costs, rate review expense, and the net removal component included in depreciation rates.

 

•        Other regulatory liabilities: This includes various regulatory liabilities that are relatively small and includes provisions for rate refunds, property taxes, emissions allowances, savings from the sale of an office building and the net removal component included in depreciation rates. Other regulatory liabilities are included in other long-term liabilities on our consolidated balance sheets.

 

A return is allowed on the KCC depreciation and coal contract settlement costs.

 

Cash and Cash Equivalents

 

We consider highly liquid investments with maturities of three months or less when purchased to be cash equivalents.

 

Restricted Cash

 

Restricted cash consists of cash irrevocably deposited in trust for a prepaid capacity and transmission agreement, letters of credit, surety bonds and escrow arrangements as required by certain letters of credit, and various other deposits.

 

Inventories and Supplies

 

Inventories and supplies are stated at average cost.

 

Property, Plant and Equipment

 

Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision, and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction projects. The AFUDC rate was 3.79% in 2004, 5.27% in 2003 and 5.95% in 2002. The cost of additions to utility plant and replacement units of property is capitalized. AFUDC capitalized was $1.8 million in 2004, $1.5 million in 2003 and $2.2 million in 2002.

 

Maintenance costs and replacement of minor items of property are charged to expense as incurred. Normally, when a unit of depreciable property is retired, the original cost, less salvage value, is charged to accumulated depreciation.

 

Depreciation

 

Utility plant is depreciated on the straight-line method at rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 2.6% during 2004, 2.5% during 2003 and 2.7% during 2002.

 

Effective April 1, 2002, we adopted new depreciation rates which reduced our annual depreciation expense by approximately $30.0 million.

 

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As part of the 2001 KCC rate order, the KCC extended the estimated retirement date for Wolf Creek from 2025 to 2045, although our operating license for Wolf Creek expires in 2025. The KCC also extended the estimated retirement date for LaCygne 2 to 2032, although the term of our lease for LaCygne 2 expires in 2016. The effect of extending the retirement date was to reduce our depreciation and amortization expense recovered in customer rates. For financial statement purposes, we recognize depreciation and amortization expense based on the current operating license and the lease term. We record a regulatory asset for the difference between the KCC allowed expense and the expense recorded for financial statement purposes.

 

Depreciable lives of property, plant and equipment are as follows.

 

     Years

Fossil fuel generating facilities

   6 to 68

Nuclear fuel generating facility

   38 to 45

Transmission facilities

   28 to 67

Distribution facilities

   19 to 57

Other

   5 to 55

 

Nuclear Fuel

 

Our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication is recorded as an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to fuel and purchased power based on the quantity of heat consumed during the generation of electricity, as measured in millions of British Thermal Units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $30.9 million at December 31, 2004 and $16.6 million at December 31, 2003. Spent fuel charged to fuel and purchased power was $19.3 million in 2004, $17.0 million in 2003 and $17.8 million in 2002.

 

Cash Surrender Value of Life Insurance

 

We recorded the following amounts related to corporate-owned life insurance policies (COLI) in other long-term assets on our consolidated balance sheets at December 31.

 

     2004

    2003

 
     (In Thousands)  

Cash surrender value of policies

   $ 967,485     $ 906,118  

Borrowings against policies

     (891,320 )     (834,673 )
    


 


COLI, net

   $ 76,165     $ 71,445  
    


 


 

Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as income on our consolidated statements of income (loss) approximated $2.0 million in 2004, $1.8 million in 2003 and $3.6 million in 2002.

 

Revenue Recognition – Energy Sales

 

We recognize revenues from retail energy sales upon delivery to the customer and include an estimate for energy delivered but unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured against billed sales. At December 31, 2004, we had estimated unbilled revenue of $47.6 million.

 

We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. Unless related to fuel, we include the net mark-to-market change in sales on our consolidated statements of income (loss). We record the resulting unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing and derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. Prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

 

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Table of Contents

Income Taxes

 

We use the asset and liability method of accounting for income taxes as required by SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties.

 

Dilutive Shares

 

Basic earnings (loss) per share applicable to equivalent common stock are based on the weighted average number of common shares outstanding and shares issuable in connection with vested restricted share units (RSUs) during the period reported. Diluted earnings (loss) per share include the effects of potential issuances of common shares resulting from the assumed vesting of all outstanding RSUs, the exercise of all outstanding stock options issued pursuant to the terms of our stock-based compensation plans and the additional issuance of shares under the employee stock purchase plan (ESPP). The dilutive effect of shares under the ESPP, stock-based compensation and stock options is computed using the treasury stock method.

 

The following table reconciles the weighted average number of common shares outstanding used to compute basic and diluted earnings (loss) per share.

 

     Year Ended December 31,

     2004

   2003

   2002

DENOMINATOR FOR BASIC AND DILUTED EARNINGS PER SHARE:

              

Denominator for basic earnings per share - weighted average shares

   82,941,374    72,428,728    71,731,580

Effect of dilutive securities:

              

Employee stock purchase plan shares

   17,515    113,737    11,030

Employee stock options

   1,943    305    —  

Restricted share awards

   680,216    924,978    527,116
    
  
  

Denominator for diluted earnings per share - weighted average shares

   83,641,048    73,467,748    72,269,726
    
  
  

Potentially dilutive shares not included in the denominator because they are antidilutive

   217,375    217,375    232,638
    
  
  

 

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Stock Based Compensation

 

For purposes of the pro forma disclosures required by SFAS No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure,” the estimated fair value of stock options is amortized to expense over the relevant vesting period. Information related to the pro forma impact on our consolidated earnings (loss) and earnings (loss) per share follows.

 

     2004

   2003

   2002

 
     (Dollars In Thousands, Except Per Share Amounts)  

Earnings (loss) available for common stock, as reported

   $ 177,900    $ 84,042    $ (793,400 )

Add: Stock-based compensation included in earnings (loss) available for common stock, as reported, net of related tax effects

     294      46      1  

Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects

     757      2,615      188  
    

  

  


Earnings (loss) available for common stock, pro forma

   $ 177,437    $ 81,473    $ (793,587 )
    

  

  


Weighted average shares used for dilution

     83,641,048      73,467,748      72,269,726  
    

  

  


Earnings (loss) per share:

                      

Basic - as reported

   $ 2.14    $ 1.16    $ (11.06 )

Basic - pro forma

   $ 2.14    $ 1.12    $ (11.06 )

Diluted - as reported

   $ 2.13    $ 1.14    $ (10.98 )

Diluted - pro forma

   $ 2.12    $ 1.11    $ (10.98 )

 

Segments of Business

 

Prior to 2004 we had identified two reportable segments: “Electric Utility” and “Other.” Our “Electric Utility” segment consisted of our integrated electric utility operations. “Other” included our former ownership interests in ONEOK, Inc. (ONEOK), Protection One, Inc. and Protection One Europe and other investments that in the aggregate were immaterial to our business or consolidated results of continuing operations.

 

With the sale of our interests in ONEOK, Protection One Europe and Protection One, we are now a vertically integrated electric utility with a single operating segment. Our chief operating decision maker evaluates our financial performance based on earnings (loss) per share of the entire company. We no longer have a distinction between segments for utility operations and other investments.

 

Supplemental Cash Flow Information

 

     2004

   2003

   2002

     (In Thousands)

CASH PAID FOR:

                    

Interest on financing activities, net of amount capitalized

   $ 127,993    $ 208,174    $ 218,066

Income taxes

     1,162      53,625      510

NON-CASH FINANCING TRANSACTIONS:

                    

Issuance of stock to subsidiary (See Note 19, “Common and Preferred Stock”)

     —        —        86,870

Issuance of common stock for reinvested dividends and RSUs

     14,674      9,505      23,146

Assets acquired through capital leases

     3,272      1,252      6,471

 

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Reclassifications

 

We have reclassified certain prior year amounts to conform with classifications used in the current-year presentation as necessary for a fair presentation of the financial statements.

 

3. RATE MATTERS AND REGULATION

 

Rate Review Request

 

As a result of an earlier KCC order, we will file a request for a rate review with the KCC by May 2, 2005, based on a test year consisting of the 12 months ended December 31, 2004.

 

Current Status of the Debt Reduction Plan

 

In 2004, we reduced, by $533.4 million, the debt shown on our consolidated balance sheet with internally generated cash, the proceeds received from the sale of Protection One, Inc. (Protection One) and proceeds from an equity offering. Additionally, due to the sale of Protection One in February 2004, we reduced the long-term debt that was included in the liabilities of discontinued operations by $305.2 million.

 

Electric Service Reliability

 

On January 16, 2004, the KCC issued an order regarding electric service reliability for retail customers. The order was intended to help the KCC assess the reliability of retail electric service. Specifically, the KCC wanted to establish uniform definitions and requirements regarding service obligations, record keeping, customer notification and methods of reporting results to the KCC. On February 10, 2004, the North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from the investigation of the August 14, 2003 blackout in portions of the northeastern United States. These initiatives will impact our operations in a number of ways, including system relay protection, vegetation management and operator training. The NERC and the ten operating regions in the United States, including the Southwest Power Pool, are working together to determine what operating policies and planning standards changes are necessary to achieve the NERC’s goals. We are unable to estimate potential compliance costs at this time, it is likely that our annual capital and maintenance expenditure requirements will increase in the future.

 

4. DISCONTINUED OPERATIONS — SALE OF PROTECTION ONE AND PROTECTION ONE EUROPE

 

In 2003, we classified our monitored security businesses as discontinued operations. We also reclassified historical periods to conform with this classification.

 

We sold our interest in Protection One Europe on June 30, 2003. The sale resulted in a $58.7 million reduction in our consolidated debt level from the buyer’s assumption of $48.2 million of Protection One Europe debt that was included on our consolidated financial statements and the use of $10.5 million of cash proceeds to pay down debt.

 

On February 17, 2004, we closed the sale of our interest in Protection One to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). At closing, we assigned to Quadrangle the senior credit facility between Westar Industries, Inc., Westar Energy’s wholly owned subsidiary, and Protection One, which had an outstanding balance of $215.5 million. At closing, we received proceeds of $122.2 million.

 

Protection One had been part of our consolidated tax group since 1997. Under the terms of a tax sharing agreement, we have reimbursed Protection One for current tax benefits used in our consolidated tax return attributable to Protection One. On November 12, 2004, we entered into a settlement agreement with Protection One and Quadrangle that, among other things, terminated a tax sharing agreement, settled Protection One’s claims with us relating to the tax sharing agreement and settled claims between Quadrangle and us relating to the sale transaction. Pursuant to the terms of the settlement agreement, Quadrangle paid us $32.5

 

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million in cash as additional consideration, and we settled tax sharing-related obligations to Protection One by tendering $27.1 million in Protection One 7-3/8% senior notes, including accrued interest, and paying $45.9 million in cash. Our net cash payment under the settlement agreement was $13.4 million. In addition, the settlement agreement provided that we would jointly agree to make an Internal Revenue Code (IRC) Section 338(h)(10) election. For tax purposes, an IRC Section 338(h)(10) election allows us to treat the sale of Protection One stock as a sale of the assets of Protection One.

 

Effective January 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 142 established new standards for accounting for goodwill. SFAS No. 142 continued to require the recognition of goodwill as an asset, but discontinued the amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. Upon the completion of the impairment tests as of January 1, 2002, we determined that the carrying values of goodwill at Protection One and Protection One Europe had been impaired and impairment charges were recorded as discussed below.

 

Another impairment test of Protection One’s goodwill and customer accounts was completed as of July 1, 2002 (the date selected for Protection One’s annual impairment test), with the independent appraisal firm providing the valuation of the estimated fair value of Protection One’s reporting units, and no impairment was indicated. Protection One’s stock price declined after regulatory orders were issued. As a result, Protection One retained the independent appraisal firm to perform an additional valuation of Protection One’s reporting units so it could perform an impairment test as of December 31, 2002, which resulted in the additional impairment charge discussed below.

 

SFAS No. 144 established a new approach to determining whether Protection One’s customer account asset was impaired. The approach no longer permitted the evaluation of the customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of Protection One, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then customer account asset carrying value must be written down to fair value, by recording an impairment.

 

The new rule substantially reduced the net undiscounted cash flows for customer account impairment evaluation purposes as compared to the previous accounting rules. Using these new guidelines, it was determined that there was an indication of impairment of the carrying value of the customer accounts and an impairment charge was recorded as discussed below.

 

To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, a charge was recorded in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.

 

Protection One completed an additional impairment test of goodwill as of December 31, 2002 and we recorded an impairment charge of $79.7 million, net of tax benefit and minority interests, in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill of Protection One’s North America segment.

 

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Results of discontinued operations are presented in the table below.

 

     Year Ended December 31,

 
     2004

    2003

    2002

 
     (In Thousands, Except Per Share Amounts)  

Sales

   $ 22,466     $ 306,938     $ 351,499  

Costs and expenses

     19,937       289,900       754,656  
    


 


 


Earnings (loss) from discontinued operations before income taxes

     2,529       17,038       (403,157 )

Estimated gain (loss) on disposal

     30,980       (258,979 )     (1,853 )

Income tax benefit

     (45,281 )     (164,036 )     (146,910 )
    


 


 


Results of discontinued operations before accounting change, net of tax

     78,790       (77,905 )     (258,100 )

Cumulative effect of accounting change, net of tax of $72,335

     —         —         (623,717 )
    


 


 


Results of discontinued operations

   $ 78,790     $ (77,905 )   $ (881,817 )
    


 


 


Basic Earnings (Loss) Per Share:

                        

Results of discontinued operations, before accounting change

   $ 0.95     $ (1.08 )   $ (3.60 )

Cumulative effect of accounting change, net of tax

     —         —         (8.69 )
    


 


 


Results of discontinued operations, net of tax

   $ 0.95     $ (1.08 )   $ (12.29 )
    


 


 


Diluted Earnings (Loss) Per Share:

                        

Results of discontinued operations, before accounting change

   $ 0.94     $ (1.06 )   $ (3.57 )

Cumulative effect of accounting change, net of tax

     —         —         (8.63 )
    


 


 


Results of discontinued operations, net of tax

   $ 0.94     $ (1.06 )   $ (12.20 )
    


 


 


 

The major classes of assets and liabilities of the monitored services businesses were as follows.

 

     December 31,
2003


     (In Thousands)

Assets:

      

Current

   $ 80,850

Property and equipment

     60,656

Customer accounts, net

     268,533

Goodwill, net

     41,847

Other

     118,655
    

Total assets

   $ 570,541
    

Liabilities:

      

Current

   $ 68,816

Long-term debt

     305,234

Other long-term liabilities

     101,547
    

Total liabilities

   $ 475,597
    

 

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5. ACCOUNTS RECEIVABLE AND VARIABLE INTEREST ENTITIES

 

Our accounts receivable on our consolidated balance sheets are comprised as follows.

 

     As of December 31,

 
     2004

    2003

 
     (In Thousands)  

Customer accounts receivable

   $ 97,017     $ 85,712  

Allowance for uncollectable accounts

     (5,152 )     (5,313 )
    


 


Transferred receivables, net

     91,865       80,399  

Other accounts receivable

     828       674  

Other allowance for uncollectable accounts

     (161 )     (102 )
    


 


Accounts receivable, net

   $ 92,532     $ 80,971  
    


 


 

Accounts Receivable Sales Program

 

WR Receivables Corporation, a wholly owned subsidiary, has an agreement with a financial institution whereby WR Receivables can sell an interest of up to $125.0 million in a designated pool of our qualified accounts receivable. The agreement expires in July 2005. Under the terms of the agreement, new receivables generated by us are continuously purchased by WR Receivables. The receivables sold to the financial institution are not reflected in the accounts receivable balance in the accompanying consolidated balance sheets. The amounts sold to the financial institution were $80.0 million at December 31, 2004 and 2003.

 

We service, administer and collect the receivables on behalf of the financial institution. Administrative expenses associated with the sale of these receivables were $2.1 million in 2004, $2.4 million in 2003 and $2.9 million in 2002. We include these expenses in other expense on our consolidated statements of income (loss).

 

We record receivables transferred to WR Receivables at book value, net of allowances for bad debts. This approximates fair value due to the short-term nature of the receivable. We include the transferred accounts receivables in accounts receivable, net, on our consolidated balance sheets. The interests that we hold are included in the table below.

 

     As of December 31,

     2004

   2003

     (In Thousands)

Accounts receivables retained by WR Receivables, net

   $ 81,842    $ 71,213

Accounts receivables reserved for purchaser, net

     10,023      9,186
    

  

Transferred receivables, net

   $ 91,865    $ 80,399
    

  

 

The following table provides gross proceeds and repayments between WR Receivables and the financial institution. We record these items on the consolidated statements of cash flows in the accounts receivable, net, line of cash flows from operating activities.

 

     Year Ended December 31,

 
     2004

    2003

    2002

 
     (In Thousands)  

Proceeds from the purchaser due to the sale of receivables

   $ 40,000     $ —       $ 30,000  

Payments to the purchaser for net collection of its receivables

     (40,000 )     (30,000 )     (20,000 )
    


 


 


Proceeds and repayments, net

   $ —       $ (30,000 )   $ 10,000  
    


 


 


 

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Consolidation of Variable Interest Entities

 

In January 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation Number (FIN) 46, “Consolidation of Variable Interest Entities,” which was subsequently revised in December 2003 with the issuance of FIN 46R. The objective of this interpretation is to provide guidance on how to identify Variable Interest Entities (VIE) and determine when the assets, liabilities, non-controlling interests and results of operations of a VIE need to be included in a company’s consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company’s interest in the VIE is such that the company will absorb a majority of the VIE’s expected losses and/or receive a majority of the entity’s expected residual returns, if they occur. FIN 46R also requires additional disclosures by primary beneficiaries and other significant variable interest holders.

 

On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. On April 16, 2004, we redeemed our entire issuance of Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, at par. On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B. On September 22, 2003, we redeemed our entire issuance of Western Resources Capital II 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, at par.

 

Provisions of FIN 46R required the deconsolidation of the Western Resources Capital I trust, which resulted in the amounts previously classified as shares subject to mandatory redemption being reclassified as long-term debt, affiliate on the consolidated balance sheet.

 

6. FINANCIAL INSTRUMENTS, ENERGY MARKETING AND RISK MANAGEMENT

 

Values of Financial Instruments

 

The carrying values and estimated fair values of our financial instruments are as shown in the table below.

 

     Carrying Value

   Fair Value

     As of December 31,

     2004

   2003

   2004

   2003

     (In Thousands)

Fixed-rate debt, net of current maturities (a)

   $ 1,419,406    $ 1,815,320    $ 1,530,035    $ 1,946,053

(a) Fair value is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions.

 

The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost, which approximates fair value and are not included in the table above.

 

The fair value estimates are based on information available at December 31, 2004 and 2003. These fair value estimates have not been comprehensively revalued since that date and current estimates of fair value may differ significantly from the amounts above.

 

Derivative Instruments and Hedge Accounting

 

We are exposed to market risks from changes in commodity prices and interest rates that could affect our consolidated results of operations and financial condition. We manage our exposure to these market risks through our regular operating and financing activities and, when deemed appropriate, economically hedge a portion of these risks through the use of derivative financial instruments. We use the term economic hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on some assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We use derivative instruments as risk management tools consistent with our business plans and prudent business practices and for energy marketing purposes.

 

We use derivative financial and physical instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, oil, coal and electricity. We classify derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales as energy marketing contracts

 

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on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities.

 

Energy Marketing Activities

 

We engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil. We use financial instruments, including forward contracts, options and swaps and we trade energy commodity contracts daily. We may also use economic hedging techniques to manage overall fuel expenditures. We procure physical product under forward agreements and spot market transactions.

 

Within the trading portfolio, we take certain positions to economically hedge a portion of physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We reflect changes in value on our consolidated statements of income (loss). We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in cash market prices and take advantage of selected market opportunities. We refer to these transactions as energy marketing activities.

 

We are involved in trading activities to reduce risk from market fluctuations, enhance system reliability and increase profits. Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations.

 

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce our overall credit risk.

 

We are also exposed to commodity price changes outside of trading activities. We use derivative contracts for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

 

We use various fossil fuel types, including coal, natural gas and oil, to operate our plants. A significant portion of our coal requirements are purchased under long-term contracts. Due to the volatility of natural gas prices, we have increasingly operated facilities that have allowed us to use lower cost fuel types as generating unit constraints and environmental restrictions allow, primarily by using oil in our facilities that also burn natural gas.

 

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and scheduled outages at our facilities that use fossil fuels and the nuclear refueling schedule. Our customers’ electricity usage could also vary from year to year based on weather or other factors.

 

Although we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio’s value. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations.

 

The prices we use to value price risk management activities reflect our estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. We consider a number of risks

 

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and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counterparties and the time value of money. We continuously monitor the portfolio and value it daily based on present market conditions.

 

Hedging Activities

 

During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases. Initially, we entered into futures and swap contracts with terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. We designated these hedging relationships as cash flow hedges.

 

In 2002, due to the increased availability of our coal units and because we began burning more oil as use of oil became more economically favorable than natural gas, we did not burn our forecasted amount of natural gas. In September 2002, we determined that we had over-hedged approximately 12,000,000 MMBtu for the remaining period of the hedge. As a result of the discontinuance of this portion of the cash flow hedge, we recognized a gain of $4.0 million. In December 2003, we determined we could no longer meet the criteria to use hedge accounting for the 2004 forecasted natural gas purchases. As a result, we recognized in income a gain of $3.7 million, of which $2.8 million had previously been recognized in other comprehensive income.

 

Effective October 4, 2001, we entered into a $500.0 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on a term loan at 6.18%. We settled the swap agreement for a nominal amount on September 29, 2003.

 

In the second quarter of 2003, we purchased a call option at a cost of $65.8 million, which locked in a settlement cost associated with a call option entered into in 1998 related to our 6.25% putable/callable notes. We settled the call option in August 2003.

 

7. PROPERTY, PLANT AND EQUIPMENT

 

The following is a summary of property, plant and equipment at December 31.

 

     2004

    2003

 
     (In Thousands)  

Electric plant in service

   $ 5,777,519     $ 5,665,479  

Electric plant acquisition adjustment

     802,318       802,318  

Accumulated depreciation

     (2,761,781 )     (2,647,214 )
    


 


       3,818,056       3,820,583  

Construction work in progress

     56,910       59,570  

Nuclear fuel, net

     35,942       29,198  
    


 


Net utility plant

     3,910,908       3,909,351  

Non-utility plant in service

     79       149  
    


 


Net property, plant and equipment

   $ 3,910,987     $ 3,909,500  
    


 


 

Depreciation expense on property, plant and equipment for the years ended December 31, 2004, 2003 and 2002 was as follows.

 

     2004

   2003

   2002

     (In Thousands)

Utility

   $ 148,933    $ 147,015    $ 151,538

Non-utility

     —        10      58
    

  

  

Total depreciation expense

   $ 148,933    $ 147,025    $ 151,596
    

  

  

 

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8. JOINT OWNERSHIP OF UTILITY PLANTS

 

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income. Information relative to our ownership interest in these facilities at December 31, 2004 is shown in the table below.

 

           Our Ownership at December 31, 2004

           In-Service
Dates


   Investment

  

Accumulated

Depreciation


  

Net

MW


  

Ownership

Percent


           (Dollars in Thousands)

LaCygne 1

   (a )   June 1973    $ 191,346    $ 118,168    344.0    50

Jeffrey 1

   (b )   July 1978      318,211      159,469    618.0    84

Jeffrey 2

   (b )   May 1980      311,333      142,225    617.0    84

Jeffrey 3

   (b )   May 1983      415,005      201,283    624.0    84

Jeffrey wind 1

   (b )   May 1999      874      230    0.6    84

Jeffrey wind 2

   (b )   May 1999      874      230    0.6    84

Wolf Creek

   (c )   Sept. 1985      1,409,238      590,055    548.0    47

State Line

   (d )   June 2001      108,099      15,115    200.0    40

                                  

(a)    Jointly owned with Kansas City Power & Light Company (KCPL)

(b)    Jointly owned with Aquila, Inc.

(c)    Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

(d)    Jointly owned with Empire District Electric Company

 

Amounts and capacity presented above represent our share. Our share of operating expenses of the above plants, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in 1987, are included in operating expenses on our consolidated statements of income (loss). Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

 

9. COMMON STOCK ISSUANCE

 

Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million.

 

10. SHORT-TERM DEBT

 

A syndicate of banks provides us a revolving credit facility on a committed basis totaling $300.0 million. The facility is secured by KGE’s first mortgage bonds and matures on March 12, 2007. It allows us to borrow up to an aggregate limit of $300.0 million, including letters of credit up to a maximum aggregate amount of $50.0 million. At December 31, 2004, we had no outstanding borrowings and $15.3 million of letters of credit outstanding under the revolving credit facility.

 

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Information regarding our short-term borrowings is as follows.

 

     As of December 31,

 
     2004

    2003

 
     (Dollars in Thousands)  

Borrowings outstanding at year end:

                

Credit agreement and an other financing arrangement

   $ —       $ 1,000  

Weighted average interest rate on debt outstanding at year-end, excluding fees

     —         6.00 %

Weighted average short-term debt outstanding during the year

   $ 1,434     $ 1,009  

Weighted daily average interest rates during the year, excluding fees

     3.50 %     6.12 %

 

Our interest expense on short-term debt was $1.1 million in 2004, $1.2 million in 2003 and $7.4 million in 2002.

 

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11. LONG-TERM DEBT

 

Outstanding Debt

 

Long-term debt outstanding at December 31 is as follows.

 

     2004

    2003

 
     (In Thousands)  

Westar Energy

                

First mortgage bond series:

                

7.875% due 2007

   $ 365,000     $ 365,000  

6.000% due 2014

     250,000       —    

8.500% due 2022

     —         125,000  

7.650% due 2023

     —         100,000  
    


 


       615,000       590,000  
    


 


Pollution control bond series:

                

Variable due 2032, 1.95% at December 31, 2004

     45,000       45,000  

Variable due 2032, 2.00% at December 31, 2004

     30,500       30,500  

6.000% due 2033

     —         58,340  

5.000 % due 2033

     58,340       —    
    


 


       133,840       133,840  
    


 


6.875% unsecured senior notes due 2004

     —         184,456  

9.750% unsecured senior notes due 2007

     260,000       387,000  

7.125% unsecured senior notes due 2009

     145,078       145,078  

6.80% unsecured senior notes due 2018

     —         26,993  

Senior secured term loan due 2005

     —         114,143  

Other long-term agreements

     —         4,179  
    


 


       405,078       861,849  
    


 


KGE

                

First mortgage bond series:

                

6.500% due 2005

     65,000       65,000  

6.200% due 2006

     100,000       100,000  
    


 


       165,000       165,000  
    


 


Pollution control bond series:

                

5.100% due 2023

     13,488       13,488  

Variable due 2027, 1.75% at December 31, 2004

     21,940       21,940  

7.000% due 2031

     —         327,500  

5.300% due 2031

     108,600       —    

5.300% due 2031

     18,900       —    

2.650% due 2031 and putable 2006

     100,000       —    

Variable due 2031, 1.92% at December 31, 2004

     100,000       —    

Variable due 2032, 1.67% at December 31, 2004

     14,500       14,500  

Variable due 2032, 1.85% at December 31, 2004

     10,000       10,000  
    


 


       387,428       387,428  
    


 


Unamortized debt discount (a)

     (1,445 )     (3,923 )

Long-term debt due within one year

     (65,000 )     (185,941 )
    


 


Long-term debt, net

   $ 1,639,901     $ 1,948,253  
    


 


Long-term debt, affiliate

   $ —       $ 103,093  
    


 



(a) We amortize debt discount over the term of the respective issue.

 

The Westar Energy mortgage and the KGE mortgage each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. Additionally, Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. Therefore, we must ensure that we will be able to comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

 

The amount of Westar Energy’s first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited subject to certain limitations as described below. The amount of KGE’s first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion, unless amended. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. At December 31, 2004, based on an assumed interest rate of

 

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6%, approximately $210.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. At December 31, 2004, based on an assumed interest rate of 6%, approximately $874.0 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

 

Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. In June 2004, Westar Energy issued $250.0 million of Westar Energy first mortgage bonds and immediately placed the funds in escrow for retirement of $225.0 million of Westar Energy first mortgage bonds, which was completed in July 2004. Therefore, at December 31, 2004, we could incur a maximum of $275.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility. Following Westar Energy’s January 18, 2005 issuance of $250.0 million of first mortgage bonds, as discussed below, we can incur a maximum of $25.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility.

 

During 2004, we recognized a loss of $16.1 million in connection with the redemption of our senior unsecured notes and $2.7 million in connection with the redemption of affiliate long-term debt.

 

On January 18, 2005, Westar Energy sold $250.0 million aggregate principal amount of Westar Energy first mortgage bonds, consisting of $125.0 million 5.15% bonds maturing in 2017 and $125.0 million 5.95% bonds maturing in 2035. On February 17, 2005, we used the net proceeds from the offering, together with cash on hand, additional funds raised through the accounts receivable conduit facility and borrowings under Westar Energy’s revolving credit facility, to redeem the remaining $260.0 million aggregate principal amount of Westar Energy 9.75% senior notes due 2007. Together with accrued interest and a premium equal to approximately 12% of the outstanding senior notes, we paid $298.5 million to redeem the Westar Energy 9.75% senior notes due 2007. After this transaction, we had $10.0 million outstanding under the revolving credit facility and $30.0 million available under the accounts receivable conduit facility.

 

Debt Covenants

 

Some of our debt instruments contain restrictions that require us to maintain various coverage and leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. These ratios are used solely to determine compliance with our various debt covenants. We were in compliance with these covenants at December 31, 2004.

 

Maturities

 

Maturities of long-term debt at December 31, 2004 are as follows.

 

Year


   Principal Amount

   (In Thousands)

2005

   $ 65,000

2006

     100,000

2007

     625,000

2008

     —  

2009

     145,078

Thereafter

     769,823
    

     $ 1,704,901
    

 

Our interest expense on long-term debt was $141.1 million in 2004, $223.2 million in 2003 and $227.8 million in 2002.

 

Affiliate Long-term Debt and Other Mandatorily Redeemable Securities

 

On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. On April 16, 2004, we redeemed our entire issuance of Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, at par. This transaction reduced our long-term liabilities by approximately $103.1 million.

 

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On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B. On September 22, 2003, we redeemed our entire issuance of Western Resources Capital II
8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, at par. This transaction reduced our long-term liabilities by approximately $115.7 million.

 

12. EMPLOYEE BENEFIT PLANS

 

Pension

 

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. Pension benefits are based on years of service and the employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Our policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain current and retired officers. Employees hired after December 31, 2001 are covered by the same defined benefit plan with benefits derived from a cash balance account formula.

 

As a co-owner of WCNOC, we are indirectly responsible for 47% of the liabilities and expenses associated with the WCNOC pension and post-retirement plans. See Note 13, “WCNOC Employee Benefit Plans” for WCNOC benefit information.

 

Our pension plan expense and liabilities are measured using assumptions, which include discount rates, compensation rates and past and future estimated plan asset returns. Due to a decrease in interest rates and a corresponding decrease in the discount rates used to estimate our pension liabilities, the fair value of our pension plan assets was less than the accumulated benefit obligation at our measurement dates of December 31, 2004 and December 31, 2003. On March 29, 2004, the Federal Energy Regulatory Commission (FERC) issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to recognize as a regulatory asset the additional minimum pension liability that otherwise would have been charged to other comprehensive income (OCI). At December 31, 2004, our additional minimum pension liability adjustment was $41.8 million, offset by an intangible asset of $15.9 million and a regulatory asset of $25.9 million. At December 31, 2003, our additional minimum pension liability was $8.7 million, offset by an intangible asset of $0.9 million and OCI of $7.8 million. We accrue the cost of post-retirement benefits during the years an employee provides service. The following tables summarize the status of our pension and other post-retirement benefit plans.

 

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At December 31,


   Pension Benefits

    Post-retirement Benefits

 
   2004

    2003

    2004

    2003

 
     (In Thousands)  

Change in Benefit Obligation:

                                

Benefit obligation, beginning of year

   $ 469,651     $ 433,620     $ 125,324     $ 124,113  

Service cost

     6,110       5,381       1,487       1,186  

Interest cost

     28,319       28,833       6,774       8,004  

Plan participants’ contributions

     —         —         2,695       2,242  

Benefits paid

     (28,880 )     (29,389 )     (12,479 )     (13,076 )

Assumption changes

     11,227       27,556       4,461       7,911  

Recognition of Medicare Part D

     —         —         (3,807 )     —    

Actuarial losses (gains)

     8,050       2,710       (989 )     (5,056 )

Amendments

     138       500       —         —    

Curtailments, settlements and special term benefits

     —         440       —         —    
    


 


 


 


Benefit obligation, end of year

   $ 494,615     $ 469,651     $ 123,466     $ 125,324  
    


 


 


 


Change in Plan Assets:

                                

Fair value of plan assets, beginning of year

   $ 409,932     $ 360,024     $ 22,543     $ 12,629  

Adjustments

     —         —         —         269  

Actual return on plan assets

     39,870       77,591       1,802       396  

Employer contribution

     —         —         17,800       19,800  

Plan participants’ contributions

     —         —         2,695       2,242  

Benefits paid

     (27,200 )     (27,683 )     (12,228 )     (12,793 )
    


 


 


 


Fair value of plan assets, end of year

   $ 422,602     $ 409,932     $ 32,612     $ 22,543  
    


 


 


 


Funded status

   $ (72,013 )   $ (59,719 )   $ (90,854 )   $ (102,781 )

Unrecognized net loss

     70,807       55,366       30,424       31,723  

Unrecognized transition obligation, net

     —         —         31,768       35,699  

Unrecognized prior service cost

     15,906       18,530       (1,398 )     (1,865 )
    


 


 


 


Prepaid (accrued) benefit costs

   $ 14,700     $ 14,177     $ (30,060 )   $ (37,224 )
    


 


 


 


Amounts Recognized in the Balance Sheets Consist Of:

                                

Prepaid benefit cost

   $ 30,597     $ 28,976     $ N/A     $ N/A  

Accrued benefit liability

     (15,897 )     (14,799 )     (30,060 )     (37,224 )

Additional minimum liability

     (41,815 )     (8,692 )     N/A       N/A  

Intangible asset

     15,906       923       N/A       N/A  

Other comprehensive income (a)

     —         7,769       N/A       N/A  

Regulatory asset (a)

     25,909       —         N/A       N/A  
    


 


 


 


Net amount recognized

   $ 14,700     $ 14,177     $ (30,060 )   $ (37,224 )
    


 


 


 



(a) On March 29, 2004, FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to record the other comprehensive income related to pension benefit obligation costs as a regulatory asset.

 

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At December 31,


   Pension Benefits

    Post-retirement Benefits

 
   2004

    2003

    2004

    2003

 
     (Dollars in Thousands)  

Accumulated Benefit Obligation

   $ 449,717     $ 429,852       N/A       N/A  

Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:

                                

Projected benefit obligation

   $ 494,615     $ 469,651       N/A       N/A  

Accumulated benefit obligation

     449,717       429,852       N/A       N/A  

Fair value of plan assets

     422,602       409,932       N/A       N/A  

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:

                                

Projected benefit obligation

   $ 494,615     $ 23,613       N/A       N/A  

Accumulated benefit obligation

     449,717       23,491       N/A       N/A  

Fair value of plan assets

     422,602       —         N/A       N/A  

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:

                                

Accumulated post-retirement benefit obligation

     N/A       N/A     $ 123,466     $ 125,324  

Fair value of plan assets

     N/A       N/A       32,612       22,543  

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:

                                

Discount rate

     5.90 %     6.10 %     5.90 %     6.10 %

Compensation rate increase

     3.00 %     3.10 %     3.00 %     3.10 %

 

We use a measurement date of December 31 for our pension and post-retirement benefit plans.

 

The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain (loss) subject to amortization is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan, without application of the amortization corridor described in SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

 

     Pension Benefits

    Post-retirement Benefits

 

For the Year Ended December 31,


   2004

    2003

    2002

    2004

    2003

    2002

 
     (Dollars in Thousands)  

Components of Net Periodic (Benefit) Cost:

                                                

Service cost

   $ 6,110     $ 5,381     $ 6,942     $ 1,487     $ 1,186     $ 1,248  

Interest cost

     28,319       28,833       28,724       6,774       8,004       7,467  

Expected return on plan assets

     (38,561 )     (40,513 )     (42,292 )     (1,999 )     (1,431 )     (52 )

Amortization of unrecognized transition obligation, net

     —         (177 )     (251 )     3,931       3,931       3,931  

Amortization of unrecognized prior service costs

     2,762       3,358       3,300       (467 )     (467 )     (467 )

Amortization of loss (gain), net

     2,525       (2,032 )     (5,932 )     1,172       1,612       919  

Curtailments, settlements and special term benefits

     —         440       12,589       —         —         —    
    


 


 


 


 


 


Net periodic (benefit) cost

   $ 1,155     $ (4,710 )   $ 3,080     $ 10,898     $ 12,835     $ 13,046  
    


 


 


 


 


 


Weighted-Average Actuarial Assumptions used to Determine Net Periodic (Benefit) Cost:

                                                

Discount rate

     6.10 %     6.75 %     7.25 %     6.10 %     6.75 %     7.25 %

Expected long-term return on plan assets

     9.00 %     9.00 %     9.00 %     8.50 %     9.00 %     9.00 %

Compensation rate increase

     3.10 %     3.75 %     4.25 %     3.10 %     3.75 %     4.25 %

 

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolio was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets. In selecting the discount rate, fixed income security yield rates for corporate high-grade bond yields are considered.

 

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In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act) became law. The Medicare Act introduced a prescription drug benefit under Medicare as well as a federal subsidy beginning in 2006. This subsidy will be paid to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. We believe our retiree health care benefits plan is at least actuarially equivalent to Medicare and is eligible for the federal subsidy. We adopted the guidance in the third quarter of 2004. Treating the future subsidy under the Medicare Act as an actuarial experience gain, as required by the guidance, decreased the accumulated post-retirement benefit obligation by approximately $4.4 million. The subsidy also decreased the net periodic post-retirement benefit cost by approximately $0.5 million for the year ended December 31, 2004.

 

For measurement purposes, the assumed annual health care cost growth rates were as follows.

 

     At December 31,

 
     2004

    2003

 

Health care cost trend rate assumed for next year

   8.00 %   9.00 %

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)

   5.00 %   5.00 %

Year that the rate reaches the ultimate trend rate

   2008     2008  

 

The health care cost trend rate has a significant effect on the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.

 

    

One-Percentage-

Point Increase


  

One-Percentage-

Point Decrease


 
     (In Thousands)  

Effect on total of service and interest cost

   $ 113    $ (111 )

Effect on post-retirement benefit obligation

     1,914      (1,878 )

 

The asset allocation for the pension plans and the post-retirement benefit plans at the end of 2004 and 2003, and the target allocations for 2005 and 2006, by asset category, are as shown in the following table.

 

     Target Allocations

    Plan Assets

 
     2006

    2005

    2004

    2003

 

Asset Category

                        

Pension Plans:

                        

Equity securities

   65 %   65 %   68 %   68 %

Debt securities

   30 %   30 %   28 %   29 %

Cash and other

   5 %   5 %   4 %   3 %
                

 

Total

               100 %   100 %
                

 

Post-retirement Benefit Plans:

                        

Equity securities

   65 %   40 %   35 %   32 %

Debt securities

   30 %   55 %   45 %   34 %

Cash and other

   5 %   5 %   20 %   34 %
                

 

Total

               100 %   100 %
                

 

 

We manage pension and retiree welfare plan assets in accordance with the “prudent investor” guidelines contained in the Employee Retirement Income Securities Act of 1974 (ERISA). The plan’s investment strategy supports the objective of the funds, which is to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to minimize the risk of large losses. We delegate investment management to specialists in each asset class and where appropriate, provide the investment manager with specific guidelines, which include

 

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allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

 

     Pension Benefits

    Post-Retirement Benefits

 
     To/(From) Trust

   

To/(From)

Company Assets


    To/(From) Trust

   

To/(From)

Company Assets


 
     (In Thousands)  

Expected cash flows:

        

Expected contributions:

                                

2005

   $ —       $ 1,900     $ 18,600     $ 300  

Expected benefit payments:

                                

2005

   $ (26,700 )   $ (1,900 )   $ (8,100 )   $ (300 )

2006

     (26,200 )     (2,000 )     (8,200 )     (300 )

2007

     (26,000 )     (1,900 )     (8,400 )     (300 )

2008

     (25,800 )     (1,800 )     (8,400 )     (300 )

2009

     (25,600 )     (1,800 )     (8,400 )     (300 )

2010 – 2014

     (137,000 )     (9,100 )     (42,500 )     (1,500 )

 

Savings Plans

 

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plans are deposited with a trustee and are invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions were $3.4 million for 2004, $3.0 million for 2003 and $2.9 million for 2002.

 

Under our qualified employee stock purchase plan established in 1999, full-time, non-union employees purchase designated shares of our common stock at no more than a 15% discounted price. Our employees purchased 185,016 shares in 2004 at an average price of $17.20 per share. Employees purchased 403,705 shares in 2003 at an average price of $8.45 per share and employees purchased 46,432 shares at an average price of $8.45 per share in 2002. We discontinued this plan effective January 1, 2005.

 

Stock Based Compensation Plans

 

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to five million shares of common stock may be granted under the LTISA Plan. At December 31, 2004, awards of 3,639,062 shares of common stock had been made under the LTISA Plan. Dividend equivalents accrue on the awarded RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on our common stock.

 

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment: An Amendment of FASB Statements No. 123 and 95.” SFAS No. 123R requires companies to recognize as compensation expense the grant-date fair value of stock options and other equity-based compensation issued to employees. The provisions of the statement are effective for financial statements issued for periods that begin after June 15, 2005, which will be our third quarter beginning July 1, 2005. We will use the modified prospective transition method. Under the modified prospective method, awards that are granted, modified or settled after the date of adoption will be measured and accounted for in accordance with SFAS No. 123R. Compensation cost for awards granted prior to, but not vested as of the date SFAS No. 123R is adopted, would be based on the grant date, fair value and attributes originally used to value those awards.

 

We currently use RSUs for stock-based awards granted to management employees. In addition, we have eliminated our employee stock purchase plan and all outstanding options have vested. Given the characteristics of our stock-based compensation program, we do not expect the adoption of SFAS No. 123R to materially impact our results of operations.

 

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In 2004, we granted 67,051 RSUs to selected management employees and directors. In 2003, we granted 559,095 RSUs to officers, selected management employees and directors. We granted 590,585 RSUs to a broad-based group of over 800 non-union employees and directors in 2002. Each RSU represents a right to receive one share of our common stock at the end of the restricted period assuming certain criteria are met. The unearned compensation related to the grant of RSUs is shown as a separate component of shareholders’ equity. Unearned compensation is being amortized to expense over the vesting period. In addition, RSUs linked to 783,400 shares of Protection One common stock and 12,193 shares of Guardian International, Inc. preferred stock held by us were granted to certain current and former officers in 2002.

 

During the second quarter of 2002, active employees awarded RSUs in prior years were allowed to exchange eligible RSUs for shares of common stock. As a result, approximately 145,000 RSUs were exchanged for approximately 105,000 shares of our common stock. In addition, approximately 317,000 RSUs held by certain executive officers were exchanged for approximately 12,500 shares of Guardian International, Inc. preferred stock held by us. Compensation expense associated with this exchange totaled approximately $9.0 million for 2002. Also, in September 2002, former employees had the opportunity to convert vested RSUs into common stock. As a result, 34,433 shares of our common stock were issued in exchange for 68,865 RSUs.

 

Another component of the LTISA Plan is the Executive Stock for Compensation program, where in the past eligible employees were entitled to receive RSUs in lieu of current cash compensation. The Executive Stock for Compensation program was modified in 2001 to pay a portion of current compensation in the form of stock. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. At the end of the deferral period, RSUs are paid in the form of stock. Plan participants were awarded 4,422 shares of common stock for dividends in 2004, 10,009 shares in 2003, and 12,121 shares in 2002. Participants received common stock distributions of 46,544 shares in 2004, 5,101 shares in 2003 and 40,097 shares in 2002.

 

Stock options under the LTISA plan are as follows.

 

     As of December 31,

     2004

   2003

   2002

     Shares

   

Weighted-

Average

Exercise

Price


   Shares

   

Weighted-

Average

Exercise

Price


   Shares

   

Weighted-

Average

Exercise

Price


     (In Thousands)          (In Thousands)          (In Thousands)      

Outstanding, beginning of year

   226.7     $ 32.92    232.6     $ 32.08    552.3     $ 34.02

Exercised

   (1.5 )     15.31    —         —      (2.6 )     18.71

Forfeited

   —         —      (5.9 )     24.99    (317.1 )     35.57
    

        

        

     

Outstanding, end of year

   225.2       32.38    226.7       32.92    232.6       32.08
    

        

        

     

 

Stock options issued and outstanding at December 31, 2004 are as follows.

 

    

Range of

Exercise

Price


  

Number

Issued

and

Outstanding


  

Weighted-

Average

Contractual

Life in Years


  

Weighted-

Average

Exercise

Price


Options - Exercisable:

                     

2000

   $15.3125    7,783    6    $ 15.31

1999

   27.8125-32.125    22,900    5      29.52

1998

   38.625-43.125    55,890    4      41.15

1997

   30.75    94,490    3      30.75

1996

   29.25    44,095    2      29.25
         
           

Total outstanding

        225,158            
         
           

 

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RSUs under the LTISA plan are as follows.

 

     As of December 31,

     2004

   2003

   2002

     Shares

   

Weighted-

Average

Exercise

Price


   Shares

   

Weighted-

Average

Exercise

Price


   Shares

   

Weighted-

Average

Exercise

Price


     (In Thousands)          (In Thousands)          (In Thousands)      

Outstanding, beginning of year

   1,913.7     $ 16.25    1,619.9     $ 18.08    1,902.9     $ 22.87

Granted

   60.1       20.57    547.3       12.90    584.2       13.28

Vested

   (668.4 )     14.65    (251.8 )     14.60    (291.8 )     18.81

Forfeited

   (7.0 )     17.72    (1.7 )     17.39    (575.4 )     28.70
    

        

        

     

Outstanding, end of year

   1,298.4       17.50    1,913.7       16.25    1,619.9       18.08
    

        

        

     

 

RSUs issued and outstanding at December 31, 2004 are as follows.

 

    

Range of

Fair Value at

Grant Date


  

Number

Issued and

Outstanding


Restricted share units:

         

2004

   $20.45    59,225

2003

   11.57 -13.95    464,731

2002

   11.57 – 17.49    180,555

2001

   17.67 – 19.61    196,820

2000

   15.3125 –19.875    264,249

1999

   27.8130 –32.125    63,783

1998

   38.625    69,000
         

Total outstanding

        1,298,363
         

 

We also issued dividend equivalents to recipients of stock options and RSUs. Recipients of RSUs receive dividend equivalents when dividends are paid on shares of company stock. The value of each dividend equivalent related to stock options is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend equivalents, with respect to stock options, expire after nine years from date of grant. The weighted-average fair value at the grant-date of the dividend equivalents on stock options was $6.40 in 2004, $6.38 in 2003 and $6.35 in 2002.

 

13. WCNOC EMPLOYEE BENEFIT PLANS

 

Pension and Post-retirement Benefits

 

The WCNOC pension plan expense and liabilities are measured using assumptions, which include discount rates, compensation rates and past and future estimated plan asset returns. Due to a decrease in interest rates and a corresponding decrease in the discount rates used to estimate pension liabilities, the fair value of WCNOC’s pension plan assets was less than the accumulated benefit obligation at the measurement dates. On March 29, 2004, the FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to recognize as a regulatory asset the additional minimum pension liability that otherwise would have been charged to other comprehensive income. At December 31, 2004, our share of WCNOC’s additional minimum pension liability adjustment was $3.1 million, offset by an intangible asset of $0.6 million and a regulatory asset of $2.5 million. At December 31, 2003, our share of WCNOC’s additional minimum pension liability was immaterial.

 

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As a co-owner of WCNOC, we are indirectly responsible for 47% of the liabilities and expenses associated with the WCNOC pension and post-retirement plans. We accrue our 47% of the WCNOC cost of pension and post-retirement benefits during the years an employee provides service. Our 47% share is included in the tables that follow.

 

     Pension Benefits

    Post-retirement Benefits

 

At December 31,


   2004

    2003

    2004

    2003

 
     (In Thousands)  

Change in Benefit Obligation:

                                

Benefit obligation, beginning of year

   $ 49,927     $ 44,519     $ 5,455     $ 4,857  

Service cost

     2,572       2,545       235       218  

Interest cost

     3,295       2,928       356       289  

Plan participants’ contributions

     —         —         147       111  

Benefits paid

     (849 )     (729 )     (416 )     (349 )

Actuarial losses

     4,223       664       325       329  
    


 


 


 


Benefit obligation, end of year

   $ 59,168     $ 49,927     $ 6,102     $ 5,455  
    


 


 


 


Change in Plan Assets:

                                

Fair value of plan assets, beginning of year

   $ 26,799     $ 22,276     $ N/A     $ N/A  

Actual return on plan assets

     2,551       2,622       N/A       N/A  

Employer contribution

     3,810       2,459       N/A       N/A  

Benefits paid

     (669 )     (558 )     N/A       N/A  
    


 


 


 


Fair value of plan assets, end of year

   $ 32,491     $ 26,799     $ N/A     $ N/A  
    


 


 


 


Funded status

   $ (26,677 )   $ (23,128 )   $ (6,102 )   $ (5,455 )

Unrecognized net loss

     15,239       11,589       2,211       2,028  

Unrecognized transition obligation, net

     398       455       461       519  

Unrecognized prior service cost

     220       252       —         —    

Post-measurement date adjustments

     740       441       —         —    
    


 


 


 


Accrued post-retirement benefit costs

   $ (10,080 )   $ (10,391 )   $ (3,430 )   $ (2,908 )
    


 


 


 


Amounts Recognized in the Balance Sheets Consist Of:

                                

Accrued benefit liability

   $ (10,080 )   $ (10,391 )   $ (3,430 )   $ (2,908 )

Additional minimum liability

     (3,144 )     (66 )     N/A       N/A  

Intangible asset

     618       35       N/A       N/A  

Other comprehensive income (a)

     —         31       N/A       N/A  

Regulatory asset (a)

     2,526       —         N/A       N/A  
    


 


 


 


Net amount recognized

   $ (10,080 )   $ (10,391 )   $ (3,430 )   $ (2,908 )
    


 


 


 



(a) On March 29, 2004, FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to record the other comprehensive income related to pension benefit obligation costs as a regulatory asset.

 

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Table of Contents
     Pension Benefits

    Post-retirement Benefits

 

At December 31,


   2004

    2003

    2004

    2003

 
     (Dollars in Thousands)  

Accumulated Benefit Obligation

   $ 46,455     $ 37,037       N/A       N/A  

Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:

                                

Projected benefit obligation

   $ 59,168     $ 49,927       N/A       N/A  

Accumulated benefit obligation

     46,455       37,037       N/A       N/A  

Fair value of plan assets

     32,491       26,799       N/A       N/A  

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:

                                

Projected benefit obligation

   $ 59,168     $ 49,927       N/A       N/A  

Accumulated benefit obligation

     46,455       37,037       N/A       N/A  

Fair value of plan assets

     32,491       26,799       N/A       N/A  

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:

                                

Accumulated post-retirement benefit obligation

     N/A       N/A     $ 6,060     $ 5,455  

Fair value of plan assets

     N/A       N/A       N/A       N/A  

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:

                                

Discount rate

     6.00 %     6.20 %     6.00 %     6.20 %

Compensation rate increase

     3.00 %     3.20 %     N/A       N/A  

 

WCNOC uses a measurement date of December 1 for the majority of its pension and post-retirement benefit plans.

 

The prior service cost is amortized on a straight-line basis over the average future service of the active plan participants benefiting under the plan at the time of the amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan, without application of the amortization corridor described in SFAS Nos. 87 and 106.

 

     Pension Benefits

    Post-retirement Benefits

 

For the Year Ended December 31,


   2004

    2003

    2002

    2004

    2003

    2002

 
     (Dollars in Thousands)  

Components of Net Periodic Cost:

                                                

Service cost

   $ 2,572     $ 2,545     $ 2,207     $ 235     $ 218     $ 166  

Interest cost

     3,295       2,928       2,613       356       289       272  

Expected return on plan assets

     (2,780 )     (2,464 )     (2,469 )     —         —         —    

Amortization of unrecognized:

                                                

Transition obligation, net

     57       57       57       58       58       57  

Prior service costs

     31       31       27       —         —         —    

Loss, net

     802       603       21       141       99       73  

Curtailments, settlements and special term benefits

     —         —         284       —         —         —    
    


 


 


 


 


 


Net periodic cost

   $ 3,977     $ 3,700     $ 2,740     $ 790     $ 664     $ 568  
    


 


 


 


 


 


Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

                                                

Discount rate

     6.20 %     6.75 %     7.25 %     6.10 %     6.50 %     7.25 %

Expected long-term return on plan assets

     9.00 %     9.00 %     9.02 %     8.50 %     N/A       N/A  

Compensation rate increase

     3.20 %     Graded rates       Graded rates       N/A       N/A       N/A  

 

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolio was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets. In selecting the discount rate, fixed income security yield rates for corporate high-grade bond yields are considered.

 

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For measurement purposes, the assumed annual health care cost growth rates were as follows.

 

     At December 31,

 
     2004

    2003

 

Health care cost trend rate assumed for next year

   8.5 %   9.0 %

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)

   5.0 %   5.0 %

Year that the rate reaches the ultimate trend rate

   2012     2012  

 

The health care cost trend rate has a significant effect on the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.

 

    

One-Percentage-

Point Increase


  

One-Percentage-

Point Decrease


 
     (In Thousands)  

Effect on total of service and interest cost

   $ 3    $ (3 )

Effect on the present value of the accumulated projected benefit obligation

     46      (45 )

 

The asset allocation for the pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category are as shown in the following table.

 

          Plan Assets

 

Asset Category


  

Target Allocation for 2005


   2004

    2003

 

Pension Plans:

                 

Equity securities

   50% - 70%    65 %   66 %

Debt securities

   30% - 50%    28 %   33 %

Other

   0%    7 %   1 %
         

 

Total

        100 %   100 %
         

 

 

WCNOC’s pension plan investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to minimize the risk of large losses. WCNOC delegates investment management to specialists in each asset class and where appropriate, provides the investment manager with specific guidelines, which include allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews.

 

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Table of Contents

Expected cash flows


   Pension Benefits

    Post-Retirement Benefits

 
     To/(From) Trust

   

To/(From)

Company Assets


    To/(From) Trust

  

To/(From)

Company Assets


 
     (In Thousands)  

Expected contributions:

                               

2005

   $ 4,700     $ 200     $ N/A    $ 300  

Expected benefit payments:

                               

2005

   $ (800 )   $ (200 )   $ N/A    $ (300 )

2006

     (900 )     (200 )     N/A      (300 )

2007

     (1,100 )     (200 )     N/A      (300 )

2008

     (1,400 )     (200 )     N/A      (400 )

2009

     (1,600 )     (200 )     N/A      (400 )

2010 – 2014

     (13,800 )     (900 )     N/A      (2,600 )

 

Savings Plan

 

WCNOC maintains a qualified 401(k) savings plan in which most of its employees participate. They match employees’ contributions in cash up to specified maximum limits. WCNOC’s contribution to the plan is deposited with a trustee and is invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. Our portion of expense associated with WCNOC’s matching contributions was $0.8 million for 2004, $0.9 million for 2003 and $0.8 million for 2002.

 

14. INCOME TAXES

 

Income tax expense (benefit) is composed of the following components at December 31.

 

     2004

    2003

    2002

 
     (In Thousands)  

Current income taxes:

                        

Federal

   $ 41,649     $ 148,117     $ (41,115 )

State

     (2,991 )     33,926       (5,515 )

Deferred income taxes:

                        

Federal

     (2,285 )     (78,069 )     31,014  

State

     1,858       (17,564 )     8,890  

Investment tax credit amortization

     (4,788 )     (4,642 )     (4,793 )
    


 


 


Total income tax expense (benefit) as reported before discontinued operations and cumulative effect of accounting change

     33,443       81,768       (11,519 )

Income tax expense (benefit) from discontinued operations:

                        

Discontinued operations

     (45,281 )     (164,036 )     (146,910 )

Cumulative effect of accounting change

     —         —         (72,335 )
    


 


 


Total income tax benefit

   $ (11,838 )   $ (82,268 )   $ (230,764 )
    


 


 


 

Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows.

 

     December 31,

     2004

   2003

     (In Thousands)

Current deferred tax assets, net

   $ 7,218    $ 123,256

Non-current deferred tax liabilities, net

     927,087      969,544
    

  

Net deferred tax liabilities

   $ 919,869    $ 846,288
    

  

 

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Temporary differences related to deferred tax assets and deferred tax liabilities are summarized in the following table.

 

     December 31,

     2004

   2003

     (In Thousands)

Deferred tax assets:

             

Deferred gain on sale-leaseback

   $ 61,241    $ 66,448

General business credit carryforward (a)

     27,645      27,524

Accrued liabilities

     18,803      19,599

Disallowed plant costs

     13,484      14,527

Long-term energy contracts

     11,194      12,034

Protection One impairment

     —        327,665

Capital loss carryforward (b)

     230,226      —  

Other

     74,875      69,074
    

  

Total gross deferred tax assets

     437,468      536,871

Less: Valuation allowance (b)

     236,588      236,214
    

  

Deferred tax assets

   $ 200,880    $ 300,657
    

  

Deferred tax liabilities:

             

Accelerated depreciation

   $ 659,776    $ 666,315

Acquisition premium

     243,165      251,163

Amounts due from customers for future income taxes, net

     191,597      207,812

Other

     26,211      21,655
    

  

Total deferred tax liabilities

   $ 1,120,749    $ 1,146,945
    

  

Net deferred tax liabilities

   $ 919,869    $ 846,288
    

  


(a)    Balance represents unutilized tax credits generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These credits expire beginning 2019 through 2024.

 

(b)    We have a net capital loss of $839.6 million available to offset past and future capital gains. The capital loss can be carried back to offset 2003 capital gains (limited to the amount of 2003 taxable income). Any excess capital loss is available for carry forward through 2009. However, as we do not expect to realize any significant capital gains in the future, a valuation allowance of $230.2 million has been established. In addition, a valuation allowance of $6.4 million has been established for certain deferred tax assets related to the write-down of investments.

 

In accordance with various rate orders, we have reduced rates to reflect the tax benefits associated with certain accelerated tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce rates charged customers for deferred taxes recovered from customers at corporate tax rates higher than the current tax rates. The rate reduction will occur as the temporary differences resulting in the excess deferred tax liabilities reverse. The tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. This liability is classified above as amounts due from customers for future income taxes.

 

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The effective income tax rates set forth below are for continuing operations. The rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective tax rates and the federal statutory income tax rates are as follows.

 

     For the Year Ended
December 31,


 
     2004

    2003

    2002

 

Statutory federal income tax rate

   35.0 %   35.0 %   35.0 %

Effect of:

                  

State income taxes

   1.0     4.3     2.8  

Amortization of investment tax credits

   (3.6 )   (1.9 )   (6.2 )

Corporate-owned life insurance policies

   (9.0 )   (5.0 )   (15.0 )

Accelerated depreciation flow through and amortization

   5.3     2.2     6.4  

Dividends received deduction

   —       (1.7 )   (12.6 )

Income tax reserve adjustment

   (5.3 )   —       (27.4 )

Capital loss utilization

   (2.2 )   —       —    

Other

   3.8     0.5     2.1  
    

 

 

Effective income tax rate

   25.0 %   33.4 %   (14.9 )%
    

 

 

 

As of December 31, 2004 and 2003, we had recorded reserves for uncertain tax positions, including interest, of $49.7 million and $55.6 million, respectively. During 2004, we reduced this reserve by $5.9 million due to a re-evaluation of estimates based on expected settlements and the finalization of the sale of Protection One. Tax reserves are established for tax deductions or income positions taken in prior income tax returns that we believe were treated properly on the tax returns but may be challenged if such tax returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of these audits is uncertain. If the positions taken on the returns are ultimately sustained, we will reverse these tax provisions to income. If the positions taken on the tax returns are not ultimately sustained, we may be required to make cash payments plus interest. We also have a tax reserve of $4.3 million (after-tax) for property and sales tax assessments by various state and local taxing authorities.

 

15. COMMITMENTS AND CONTINGENCIES

 

Purchase Orders and Contracts

 

As part of our ongoing operations and construction program, we have purchase orders and contracts, excluding fuel, which is discussed below under “— Fuel Commitments,” that have an unexpended balance of approximately $159.4 million at December 31, 2004, of which $34.6 million has been committed. The $34.6 million commitment relates to purchase obligations issued and outstanding at year-end.

 

The yearly detail of the aggregate amount of required payments at December 31, 2004 was as follows.

 

    

Committed

Amount


     (In Thousands)

2005

   $ 28,601

2006

     3,668

2007

     2,343
    

     $ 34,612
    

 

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Clean Air Act

 

Generally, we must comply with the Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on major pollutants, including sulfur dioxide (SO2), particulate matter and nitrogen oxides (NOx). In addition, we must comply with the provisions of the Clean Air Act Amendments of 1990 that require a two-phase reduction in some emissions. We have installed continuous monitoring and reporting equipment in order to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II SO2 and NOx requirements.

 

EPA New Source Review

 

The Environmental Protection Agency (EPA) is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to New Source Review requirements or New Source Performance Standards under Section 114(a) of the Clean Air Act (Section 114). These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could have reasonably been expected to result in a significant net increase in emissions. The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to remove emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

 

The EPA has requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.

 

We are in discussions with the EPA concerning this matter in an attempt to reach a settlement. We expect that any settlement with the EPA could require us to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years. Additionally, we might be required to update or install emissions controls at our other coal-fired plants, pay fines or penalties, or take other remedial action. Together, these costs could be material. The EPA has informed us that it has referred this matter to the Department of Justice (DOJ) for the DOJ to consider whether to pursue an enforcement action in federal district court. We believe that costs related to updating or installing emissions controls would qualify for recovery through rates. If we were to reach a settlement with the EPA, we may be assessed a penalty. The penalty could be material and may not be recovered in rates.

 

Manufactured Gas Sites

 

We have been associated with a number of former manufactured gas sites located in Kansas and Missouri that may contain coal tar and other potentially harmful materials.

 

We and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and remediate, if necessary, these sites. Through December 31, 2004, the costs incurred for preliminary site investigation and risk assessment have been minimal. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the Kansas sites, our liability for twelve of the Kansas sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three Kansas sites. With respect to two of those sites, we are currently either conducting or completing remediation activities and, with respect to the third site, we will begin investigation activities in the near future.

 

Our liability for our former manufactured gas sites in Missouri is limited by an environmental indemnity agreement with Southern Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our future liability for these sites is capped at $7.5 million and terminates in 2009.

 

Solid Waste Landfills

 

We operate solid waste landfills at Jeffrey, Lawrence and Tecumseh Energy Centers for the single purpose of disposing of coal combustion waste material. Additionally, there is one retired landfill at each of the Lawrence and Neosho Energy Centers. All landfills are permitted by the KDHE. The operating landfill at Lawrence Energy Center is projected to be full by late 2007 or early 2008 requiring us to permit and construct a new landfill at this site. We began the process of obtaining this permit in late 2003. We will continue to work with the appropriate regulatory agencies to ensure that the new landfill and expansion of the existing landfill will meet the operating requirements of the Lawrence Energy Center.

 

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Nuclear Decommissioning

 

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that funds required for nuclear decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.

 

We expense nuclear decommissioning costs over the expected life of Wolf Creek. The amount we expense is based on an estimate of nuclear decommissioning costs that we will incur upon retirement of the plant. Nuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2004, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. Fair value approximated $91.1 million at December 31, 2004 and $80.1 million at December 31, 2003.

 

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the nuclear decommissioning study, the current-year funding and future funding. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount for the pro rata share of the plant.

 

We filed an updated nuclear decommissioning and dismantlement cost estimate with the KCC on August 30, 2002. Estimated costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied on site-specific, technical information, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s nuclear decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220.0 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

 

The KCC issued an order on April 16, 2003 approving the August 2002 nuclear decommissioning study for Wolf Creek. On June 2, 2003, we filed a funding schedule with the KCC to reflect the KCC’s April 16, 2003 order. On October 10, 2003, the KCC approved the funding schedule as filed without any change to our funding obligation.

 

We charge nuclear decommissioning costs to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the funding schedule in the KCC’s October 13, 2003 order. Electric rates charged to customers provide for recovery of these nuclear decommissioning costs over the life of Wolf Creek, which, as determined by the KCC for purposes of the funding schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear decommissioning fund by the time our license expires in 2025. We believe that the KCC approved funding level will be sufficient to meet the NRC minimum financial assurance requirement. However, our consolidated results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.

 

Storage of Spent Nuclear Fuel

 

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. As required by federal law, the WCNOC co-owners entered into a standard contract with the DOE in 1984 in which the DOE promised to begin accepting from commercial nuclear power plants their used nuclear fuel for disposal beginning in early 1998. In return, Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. The fee is one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. We include these disposal costs in operating expenses.

 

A permanent disposal site will not be available for the nuclear industry until 2012 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2018. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

 

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In 2002, the Yucca Mountain site in Nevada was approved for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. This action allows the DOE to apply to the NRC to license the project. The DOE expects that this facility will open in 2012. However, the opening of the Yucca Mountain site has been delayed many times and could be delayed further due to litigation and other issues related to the site as a permanent repository for spent nuclear fuel.

 

Nuclear Insurance

 

We maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear and war. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts, as defined by the Terrorism Risk Insurance Act, of terrorism-related losses, including replacement power costs. An industry aggregate limit of $300.0 million exists for liability claims, regardless of the number of non-certified acts affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.24 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), our insurance provider, exists for property claims, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

 

Nuclear Liability Insurance

 

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently approximately $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $300.0 million, and the remaining $10.5 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $100.6 million per incident at any commercial reactor in the country, payable at no more than $10.0 million per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of our worker radiation claims insurance. In addition, Congress could impose additional revenue-raising measures to pay claims. If the $10.8 billion liability limitation is insufficient, Congress will consider taking whatever action is necessary to compensate the public for valid claims.

 

The Price-Anderson Act expired in August 2002 but was extended until December 31, 2003 for Licensees. Licensees such as Wolf Creek continue to be grandfathered under the Act. The current version of a comprehensive energy bill expected to be adopted in 2005 by Congress contains provisions that would amend Federal Law (the “Price-Anderson Act”) addressing public liability from nuclear energy hazards in ways that would increase the annual limit on retrospective assessments from $10.0 million to $15.0 million per reactor per incident.

 

Nuclear Property Insurance

 

The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion (our share is $1.3 billion). This insurance is provided by NEIL. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met, including nuclear decommissioning the plant, toward a shortfall in the nuclear decommissioning trust fund.

 

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Accidental Nuclear Outage Insurance

 

The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $26.0 million (our share is $12.2 million).

 

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on our consolidated financial condition and results of operations.

 

Fuel Commitments

 

To supply a portion of the fuel requirements for our generating plants, we have entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 2004, our share of WCNOC’s nuclear fuel commitments were approximately $13.5 million for uranium concentrates expiring in 2007, $1.7 million for conversion expiring in 2007, $8.6 million for enrichment expiring at various times through 2006 and $52.4 million for fabrication through 2024.

 

At December 31, 2004, our coal and coal transportation contract commitments in 2004 dollars under the remaining terms of the contracts were approximately $1.5 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013.

 

At December 31, 2004, our natural gas transportation commitments in 2004 dollars under the remaining terms of the contracts were approximately $43.5 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016.

 

Energy Act

 

As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and nuclear decommissioning fund. Our portion of the assessment, including carrying costs, for Wolf Creek is approximately $11.1 million, adjusted for inflation. To date, we have paid approximately $9.7 million, with the estimated remainder payable over the next two years. We recover such costs from prices we charge our customers.

 

16. ASSET RETIREMENT OBLIGATIONS

 

In January 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Any income effects are offset by regulatory accounting pursuant to SFAS No. 71.

 

Legal Liability - Wolf Creek

 

On January 1, 2003, we recognized the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the present value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. We also established a regulatory asset for $64.0 million, which represents the accretion of the liability since 1985 and the increased depreciation expense associated with the increase in plant. The asset retirement obligation is included on our consolidated balance sheets in other long-term liabilities. Currently, we recover costs to retire Wolf Creek through rates as provided by the KCC.

 

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The following table is a reconciliation of the legal asset retirement obligation related to the nuclear decommissioning of WCNOC, which is included on our consolidated balance sheets in other long-term liabilities.

 

    

As of

December 31, 2004


     (In Thousands)

Beginning asset retirement obligation

   $ 80,695

Accretion expense

     6,423
    

Ending asset retirement obligation

   $ 87,118
    

 

Non-legal Liability - Cost of Removal

 

We have recovered amounts in rates to provide for recovery of the probable costs of removing utility plant assets, but which do not represent legal retirement obligations. At December 31, 2004, Westar Energy had $1.3 million in removal costs classified as a regulatory asset and KGE had $2.6 million in removal costs classified as a regulatory liability. At December 31, 2003, we had $6.6 million in removal costs classified as a regulatory asset. The net amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to removal costs incurred.

 

17. LEGAL PROCEEDINGS

 

We and certain of our present and former officers are defendants in a consolidated purported class action lawsuit in United States District Court in Topeka, Kansas, “In Re Westar Energy, Inc. Securities Litigation,” Master File No. 5:03-CV-4003 and related cases. Plaintiffs filed a Consolidated Amended Complaint on July 15, 2003. The lawsuit is brought on behalf of purchasers of our common stock between March 29, 2000, the date we announced our intention to separate our electric utility operations from our unregulated businesses, and November 8, 2002, the date the KCC issued an order prohibiting the separation. The lawsuit alleges that we violated federal securities laws by making material misrepresentations or omitting material facts concerning the purpose and benefits of the previously proposed separation of our electric utility operations from our unregulated businesses, the compensation of our senior management and the independence and functioning of our board of directors, and that as a result we artificially inflated the price of our common stock. On August 26, 2004, the court issued an order granting a joint motion of all parties requesting a stay of the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The court also denied without prejudice motions to dismiss the lawsuit filed by us and other defendants. The court stated its intention to set aside the order upon notice by any party that mediation efforts were unsuccessful, in which case the court would address the motions to dismiss the lawsuit. The stay was subsequently extended to March 18, 2005. We intend to vigorously defend against this action. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

 

We and certain of our present and former officers and employees are defendants in a consolidated purported class action lawsuit filed in United States District Court in Topeka, Kansas, “In Re Westar Energy ERISA Litigation, Master File No. 03-4032-JAR.” Plaintiffs filed a Consolidated Amended complaint on October 20, 2003. The lawsuit is brought on behalf of participants in, and beneficiaries of, our Employees’ 401(k) Savings Plan between July 1, 1998 and January 1, 2003. The lawsuit alleges violations of the Employee Retirement Income Security Act arising from the conduct of certain present and former officers and employees who served or are serving as fiduciaries for the plan. The conduct is related to alleged securities law violations related to the previously proposed separation of our electric utility operations from our unregulated businesses, our rate reviews filed with the KCC in 2000, the compensation of and benefits provided to our senior management, energy marketing transactions with Cleco Corporation and the first and second quarter 2002 restatements of our consolidated financial statements related to the revised goodwill impairment charge and the mark-to-market charge on our putable/callable notes. On August 26, 2004, the court issued an order granting a joint motion of all parties requesting a stay of the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The court also denied without prejudice motions to dismiss the lawsuit filed by us and other defendants. The court stated its intention to set aside the order upon notice by any party that mediation efforts were unsuccessful, in which case the court would address the motions to dismiss the lawsuit. The stay was extended to February 8, 2005. On February 8, 2005, the court held a conference at which the parties notified the court that efforts to settle the lawsuit through mediation had not been successful. The court then issued an order renewing the

 

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previously filed motions to dismiss and set a scheduling conference on March 8, 2005 to address the scope and timing of discovery in the lawsuit. We intend to vigorously defend against this action. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

 

Certain present and former members of our board of directors and officers are defendants in a shareholder derivative complaint filed April 18, 2003, “Mark Epstein vs David C. Wittig, Douglas T. Lake, Charles Q. Chandler IV, Frank J. Becker, Gene A. Budig, John C. Nettels, Jr., Roy A. Edwards, John C. Dicus, Carl M. Koupal, Jr., Larry D. Irick and Cleco Corporation, defendants, and Westar Energy, Inc., nominal defendant, Case No. 03-4081-JAR.” Plaintiffs filed an amended shareholder derivative complaint on July 30, 2003. Among other things, the lawsuit claims that the defendants (i) breached fiduciary duties owed to us because of the actions and omissions described in the report of the special committee of our board of directors, (ii) caused or permitted our assets to be wasted on perquisites for certain insiders and (iii) caused or permitted our May 6, 2002 proxy statement to be issued with materially false and misleading statements. The plaintiffs seek unspecified monetary damages and other equitable relief. In October 2003, our board of directors appointed a special litigation committee of the board to evaluate the amended shareholder derivative complaint. The members of the committee were Mollie H. Carter, Arthur B. Krause and Michael F. Morrissey. On August 26, 2004, the court issued an order granting a joint motion of all parties requesting a stay of the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The stay was subsequently extended to March 18, 2005. Plaintiffs have informed us they intend to file a motion seeking leave to amend the amended consolidated complaint if the mediation efforts are unsuccessful. The court would then set a date for us, and other defendants who have not already filed a response to the complaint, to respond to the amended complaint. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

 

On June 13, 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against David C. Wittig, our former president, chief executive officer and chairman, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, arising out of their previous employment with us. Mr. Wittig and Mr. Lake have filed counterclaims against us in the arbitration alleging substantial damages related to the termination of their employment and the publication of the report of the special committee of our board of directors. We intend to vigorously defend against these claims. The arbitration has been stayed pending the completion of a trial scheduled to begin May 9, 2005, of Mr. Wittig and Mr. Lake on criminal charges in U.S. District Court in the District of Kansas. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

 

We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect on our consolidated financial position or results of operations.

 

See also Notes 3, 15, 18 and 20 for discussion of KCC regulatory proceedings, alleged violations of the Clean Air Act, an investigation by the United States Attorney’s Office, an inquiry by the Securities and Exchange Commission (SEC), an investigation by FERC and potential liabilities to Mr. Wittig and Mr. Lake.

 

18. ONGOING INVESTIGATIONS

 

Grand Jury Subpoena

 

On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of our aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock that was abandoned; and the company in general. We are providing information in response to these requests and we are cooperating fully in the investigation. We have not been informed that we are a target of the investigation. On December 4, 2003, Mr. Wittig and Mr. Lake were indicted by the federal grand jury on conspiracy, fraud and other criminal charges related to their actions while serving as our officers. The trial on these charges was held in 2004 and ended with a mistrial. A new trial is scheduled to begin on May 9, 2005. We are unable to predict the ultimate outcome of the investigation or its impact on us.

 

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Securities and Exchange Commission Inquiry

 

On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these and other matters within the scope of the grand jury investigation, including disclosures in our proxy statements concerning personal aircraft use by former officers and the payment of a bonus to Mr. Wittig in 2002. We are unable to predict the ultimate outcome of the inquiry or its impact on us.

 

FERC Subpoena

 

On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries. We have provided information to FERC in response to the original subpoena, subsequent requests submitted through our counsel and additional subpoenas received July 28, 2003 and October 27, 2003 seeking information about compliance with FERC codes of conduct applicable to generation and transmission activities. We believe that our participation in these transactions and the conduct of our generation and transmission operations did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation.

 

Department of Labor Investigation

 

On February 1, 2005, we received a subpoena from the Department of Labor seeking documents related to our Employees’

401(k) Savings Plan and our defined benefit pension plan. At this time, we do not know the specific purpose of the investigation and we are unable to predict the ultimate outcome of the investigation or its impact on us. See Note 17, “Legal Proceedings,” for discussion of a class action lawsuit brought on behalf of participants in our Employees’ 401(k) Savings Plan.

 

19. COMMON AND PREFERRED STOCK

 

Westar Energy’s articles of incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2004, we had 86,029,721 shares issued and outstanding.

 

Westar Energy has a direct stock purchase plan (DSPP). Shares sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2004, a total of 1,318,079 shares were issued by Westar Energy for the DSPP, the employee stock purchase plan and other stock based plans operated under the 1996 Long-Term Incentive and Share Award Plan. At December 31, 2004, a total of 5,412,096 shares were available under the DSPP registration statement.

 

Treasury Stock

 

At December 31, 2004, Westar Energy did not have any treasury stock. At December 31, 2003, Westar Energy had a treasury stock balance of 203,575 shares.

 

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Preferred Stock Not Subject to Mandatory Redemption

 

Westar Energy’s cumulative preferred stock is redeemable in whole or in part on 30 to 60 days’ notice at our option. The table below shows our redemption amount for all series of preferred stock not subject to mandatory redemption at December 31, 2004.

 

Rate


   Shares

  

Principal

Outstanding


  

Call

Price


    Premium

  

Total

Cost

to Redeem


     (Dollars in Thousands)

4.500%

   121,613    $ 12,161    108.00 %   $ 973    $ 13,134

4.250%

   54,970      5,497    101.50 %     82      5,579

5.000%

   37,780      3,778    102.00 %     76      3,854
         

        

  

          $ 21,436          $ 1,131    $ 22,567
         

        

  

 

The provisions of Westar Energy’s articles of incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. If the ratio of the capital represented by our preference stock and common stock (together, Subordinated Stock), including premiums on our capital stock and its surplus accounts, to its total capital and its surplus accounts at the end of the second month immediately preceding the date of the proposed payment of dividends, adjusted to reflect the proposed payment (Capitalization Ratio), will be less than 20%, then the payment of the dividends on Subordinated Stock shall not exceed 50% of net income available for dividends for the 12-month period ending with and including the second month immediately preceding the date of the proposed payment. If the Capitalization Ratio is 20% or more but less than 25%, then the payment of dividends on the Subordinated Stock, including the proposed payment, shall not exceed 75% of its net income available for dividends for such 12-month period. Except to the extent permitted above, no payment or other distribution may be made that would reduce the Capitalization Ratio to less than 25%. The Capitalization Ratio is determined based on the unconsolidated balance sheet for Westar Energy. At December 31, 2004, the Capitalization Ratio was greater than 25%.

 

So long as there are any outstanding shares of Westar Energy preferred stock, Westar Energy shall not without the consent of a majority of the shares of preferred stock or if more than one-third of the outstanding shares of preferred stock vote negatively and without the consent of a percentage of any and all classes required by law and Westar Energy’s articles of incorporation, declare or pay any dividends (other than stock dividends or dividends applied by the recipient to the purchase of additional shares) or make any other distribution upon Subordinated Stock unless, immediately after such distribution or payment the sum of Westar Energy’s capital represented by the outstanding Subordinated Stock and our earned and any capital surplus shall not be less than $10.5 million plus an amount equal to twice the annual dividend requirement on all the then outstanding shares of preferred stock.

 

20. POTENTIAL LIABILITIES TO DAVID C. WITTIG AND DOUGLAS T. LAKE

 

David C. Wittig, our former chairman of the board, president and chief executive officer, resigned from all of his positions with us and our affiliates on November 22, 2002. On May 7, 2003, our board of directors determined that the employment of Mr. Wittig was terminated as of November 22, 2002 for cause. Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, was placed on administrative leave from all of his positions with us and our affiliates on December 6, 2002. On June 12, 2003, our board of directors terminated the employment of Mr. Lake for cause.

 

On June 13, 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against Mr. Wittig and Mr. Lake arising out of their previous employment with us. Among other things, we are seeking to recover compensation and benefits previously paid to Mr. Wittig and Mr. Lake and to avoid compensation and other benefits Mr. Wittig and Mr. Lake claim to be owed to them as a result of their previous employment with us. We are unable to predict the outcome of the arbitration.

 

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At December 31, 2004, we had accrued liabilities totaling approximately $57.8 million for compensation not yet paid to Mr. Wittig and Mr. Lake under various plans. The compensation includes RSU awards, deferred vested shares, deferred RSU awards, deferred vested stock for compensation, executive salary continuation plan benefits and, in the case of Mr. Wittig, benefits arising from a split dollar life insurance agreement. The amount of our obligation to Mr. Wittig related to a split dollar life insurance agreement is subject to adjustment at the end of each quarter based on the total return to our shareholders from the date of that agreement. The total return considers the change in stock price and accumulated dividends. These compensation-related accruals are included in long-term liabilities on the consolidated balance sheets with a portion recorded as a component of paid in capital. The amount accrued will increase annually as it relates to future dividends on deferred RSU awards and increases in amounts that may be due under the executive salary continuation plan.

 

In addition, we accrued $4.2 million at December 31, 2004 for legal fees and expenses incurred by Mr. Wittig and Mr. Lake that are recorded in accounts payable on our consolidated balance sheets. We will likely incur substantial additional expenses for legal fees and expenses incurred by Mr. Wittig and Mr. Lake related to the arbitration proceeding discussed above, the defense of the criminal charges filed by the United States Attorney’s Office in Topeka, Kansas, against Mr. Wittig and Mr. Lake, and the legal proceedings described in Note 17, “Legal Proceedings,” above. We are unable to estimate the amount of the additional legal fees and expenses that will be incurred by Mr. Wittig and Mr. Lake for which we may be ultimately responsible. We are also currently unable to determine the amount of the fees which may be recovered under any applicable directors and officers liability insurance policies.

 

In addition to these amounts, we could also be obligated to make payments to Mr. Wittig and Mr. Lake pursuant to the executive salary continuation plan. Assuming an expected payout period of 35 years, the aggregate nominal amount of these payments would be approximately $16.6 million for Mr. Wittig and $8.3 million for Mr. Lake.

 

21. REDEMPTION OF GUARDIAN INTERNATIONAL PREFERRED STOCK

 

On July 9, 2004, Guardian International, Inc. (Guardian) redeemed 8,397 shares of Guardian Series C preferred stock held of record by us. The redemption price was $8.6 million, representing the par value of $1,000 per share, or $8.4 million, plus $0.2 million in accrued dividends through the date of redemption and the redemption premium. In 2002, we granted certain current and former officers 540 RSUs linked to these securities. In 2002, we also transferred beneficial ownership of 4,714 shares of Guardian Series C preferred stock to Mr. Wittig and Mr. Lake in exchange for other securities. The ownership of these shares and related dividends is disputed and is the subject of the arbitration proceeding with Mr. Wittig and Mr. Lake discussed above in Note 17, “Legal Proceedings.” We recorded an approximate $0.6 million increase in the balance of our potential liability to Mr. Wittig and Mr. Lake in the third quarter to reflect the difference between the carrying value of the 4,714 shares claimed by Mr. Wittig and Mr. Lake and the redemption amount.

 

22. MARKETABLE SECURITIES

 

On January 1, 2003, we classified our investment in ONEOK as an available-for-sale security. During 2003, we sold our investment in ONEOK and recorded a pre-tax gain of $99.3 million. The following table summarizes our marketable security sales for the years ended December 31, 2004, 2003 and 2002.

 

     Marketable Security Sales

     2004

          2003

          2002

     (In Thousands)

Sales proceeds

   $         —             $ 801,841           $         —  

Realized gains

     —               99,327             —  

 

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23. LEASES

 

Operating Leases

 

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates ranging from 1 to 15 years. We have the right at the expiration of the basic lease terms to renew several leases, including the LaCygne 2 lease, static var equipment lease, and several railcar leases. We also have the right to purchase the equipment or assets at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the equipment if certain notification requirements are met.

 

In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term. The rental expense associated with the LaCygne 2 operating lease includes an offset for the amortization of the deferred gain on the sale-leaseback. The rental expense and estimated commitments are as follows for the LaCygne 2 lease and other operating leases.

 

Year Ended December 31,


   LaCygne 2
Lease (a)


   Total
Operating
Leases


     (In Thousands)

Rental expense:

             

2002

   $ 28,895    $ 46,312

2003

     28,895      42,495

2004

     28,895      38,793

Future commitments:

             

2005

   $ 38,013    $ 49,422

2006

     42,287      53,239

2007

     78,268      86,802

2008

     12,609      20,343

2009

     42,287      48,802

Thereafter

     289,154      355,290
    

  

Total future commitments

   $ 502,618    $ 613,898
    

  


(a)    The LaCygne 2 lease amounts are included in the total operating leases column.

 

In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operating and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the lease term. The increase in payments in 2006 and 2007 represents a change in accordance with the terms of the lease from the lease payments being made in arrears to the lease payments being made in advance and are included on a straight-line basis over the minimum lease term when determining lease expense.

 

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Capital Leases

 

Capital leases are identified based on the requirements set forth in SFAS No. 13, “Accounting for Leases.” For both vehicles and computer equipment, new leases are signed each month based on the terms of the master lease agreement. The lease term for vehicles is from 5 to 14 years depending on the type of vehicle. The computer equipment has either a 2- or 3-year term. Assets recorded under capital leases are listed below.

 

     December 31,

 
     2004

    2003

 
     (In Thousands)  

Vehicles

   $ 35,769     $ 40,018  

Computer equipment and software

     2,145       1,118  

Accumulated amortization

     (17,848 )     (18,543 )
    


 


     $ 20,066     $ 22,593  
    


 


 

Capital lease payments are currently treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases at December 31, 2004 are listed below.

 

Year Ended December 31,


   Total Capital
Leases


 
     (In Thousands)  

2005

   $ 5,267  

2006

     4,545  

2007

     4,024  

2008

     3,284  

2009

     2,619  

Thereafter

     4,462  
    


       24,201  

Amounts representing imputed interest

     (4,135 )
    


Present value of net minimum lease payments under capital leases

   $ 20,066  
    


 

24. RELATED PARTY TRANSACTIONS — ONEOK Shared Services Agreement

 

We and ONEOK had shared services agreements in which we provided and billed one another for facilities, utility field work, mobile communications, information technology, customer support, meter reading and bill processing. Payments for these services were based on various hourly charges, negotiated fees and out-of-pocket expenses.

 

     2004

   2003

   2002

     (In Thousands)

Charges to ONEOK

   $ 7,213    $ 8,312    $ 8,357

Charges from ONEOK

     2,735      3,190      3,324

 

ONEOK terminated portions of this shared services agreement in September 2004, including electric service orders, call center functions, bill processing and remittance processing. In addition to joint meter reading, we plan to continue to share some facilities and a mobile communications system.

 

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25. WORK FORCE REDUCTIONS – 2002 Voluntary Separation

 

During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We have replaced and may continue to replace some of these employees. Below is a schedule of severance payments incurred related to this workforce reduction.

 

     Year Ended
December 31, 2002


 
     (In Thousands)  

Balance at January 1

   $ —    

Additions

     19,496  

Payments

     (19,496 )
    


Balance at December 31

   $ —    
    


 

Any work force reductions since the completion of the 2002 voluntary separation have been in the normal course of operations.

 

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26. QUARTERLY RESULTS (UNAUDITED)

 

Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. In addition, our net results of discontinued operations varied between comparable quarters. In the first quarter of 2003, we classified our monitored security business as discontinued operations requiring the recognition of certain tax benefits resulting in net income from discontinued operations of $103.8 million. In the third quarter of 2003, we wrote down our monitored security business to our estimate of realizable value resulting in a net loss of $161.7 million. In the fourth quarter of 2004, we recognized income from discontinued operations of $71.9 million, which reflects the results of the final settlement of all issues related to the sale of our monitored security business.

 

     First

   Second

   Third

   Fourth

     (In Thousands, Except Per Share Amounts)

2004


                           

Sales

   $ 340,263    $ 358,430    $ 421,489    $ 344,307

Income from continuing operations

     8,791      13,979      60,369      16,941

Results of discontinued operations, net of tax

     6,888      —        —        71,902

Net income

     15,679      13,979      60,369      88,843

Earnings available for common stock

   $ 15,437    $ 13,737    $ 60,127    $ 88,599

Per Share Data (a):

                           

Basic:

                           

Earnings available from continuing operations

   $ 0.12    $ 0.16    $ 0.70    $ 0.19

Discontinued operations, net of tax

     0.09      —        —        0.84
    

  

  

  

Earnings available

   $ 0.21    $ 0.16    $ 0.70    $ 1.03
    

  

  

  

Diluted:

                           

Earnings available from continuing operations

   $ 0.12    $ 0.16    $ 0.69    $ 0.19

Discontinued operations, net of tax

     0.09      —        —        0.83
    

  

  

  

Earnings available

   $ 0.21    $ 0.16    $ 0.69    $ 1.02
    

  

  

  

Cash dividend declared per common share

   $ 0.19    $ 0.19    $ 0.19    $ 0.23

Market price per common share:

                           

High

   $ 21.00    $ 21.47    $ 21.11    $ 22.92

Low

   $ 18.06    $ 18.24    $ 19.58    $ 20.05

(a)     Earnings (loss) per share is computed independently for each of the periods presented. The sum of the earnings (loss) per share amounts for the quarters may not equal the total for the year.

 

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     First

   Second

   Third

    Fourth

 
     (In Thousands, Except Per Share Amounts)  

2003


                              

Sales

   $ 345,434    $ 345,885    $ 438,167     $ 331,657  

Income from continuing operations

     20,102      21,807      80,584       40,422  

Results of discontinued operations, net of tax

     103,822      6,378      (161,651 )     (26,454 )

Net income (loss)

     123,924      28,185      (81,067 )     13,968  

Earnings (loss) available for common stock

   $ 123,697    $ 27,943    $ (81,283 )   $ 13,686  

Per Share Data (a):

                              

Basic:

                              

Earnings available from continuing operations

   $ 0.28    $ 0.30    $ 1.11     $ 0.56  

Discontinued operations, net of tax

     1.44      0.09      (2.23 )     (0.37 )
    

  

  


 


Earnings (loss) available

   $ 1.72    $ 0.39    $ (1.12 )   $ 0.19  
    

  

  


 


Diluted:

                              

Earnings available from continuing operations

   $ 0.27    $ 0.30    $ 1.09     $ 0.54  

Discontinued operations, net of tax

     1.44      0.08      (2.20 )     (0.35 )
    

  

  


 


Earnings (loss) available

   $ 1.71    $ 0.38    $ (1.11 )   $ 0.19  
    

  

  


 


Cash dividend declared per common share

   $ 0.19    $ 0.19    $ 0.19     $ 0.19  

Market price per common share:

                              

High

   $ 13.04    $ 17.09    $ 18.65     $ 20.49  

Low

   $ 9.76    $ 12.15    $ 15.45     $ 18.40  

(a)     Earnings (loss) per share is computed independently for each of the periods presented. The sum of the earnings (loss) per share amounts for the quarters may not equal the total for the year.

       

 

27. SUBSEQUENT EVENT – Ice Storm

 

On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric service in a large portion of our service territory and damaged a significant portion of our electric distribution system. We estimate that we will incur $38.0 million to $42.0 million of system restoration costs. Of this amount, we expect $6.0 million to $8.0 million to be accounted for as capital expenditures and we expect the balance related to maintenance expenditures to be accounted for as a regulatory asset. On February 3, 2005, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery maintenance costs related to system restoration. We can provide no assurance that the KCC will approve our application, however, in the past the KCC has approved similar requests.

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

ITEM 9A. CONTROLS AND PROCEDURES

 

Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and its subsidiaries is communicated to the chief executive officer and the chief financial officer. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, at December 31, 2004, our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

 

There were no changes in our internal control over financial reporting during the fourth quarter ended December 31, 2004, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

See Item 8. Financial Statements and Supplementary Data for Management’s Annual Report On Internal Control Over Financial Reporting and the Independent Registered Public Accounting Firm’s report with respect to management’s assessment of the effectiveness of internal control over financial reporting.

 

ITEM 9B. OTHER INFORMATION

 

None.

 

PART III

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

 

The information concerning directors required by Item 401 of Regulation S-K will be included under the caption “Election of Directors” in our definitive Proxy Statement for our 2005 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A (the 2005 Proxy Statement), and that information is incorporated by reference in this Form 10-K. Information concerning executive officers required by Item 401 of Regulation S-K is located under Part I, Item 1 of this Form 10-K. The information required by Item 405 of Regulation S-K concerning compliance with Section 16(a) of the Exchange Act will be included under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2005 Proxy Statement, and that information is incorporated by reference in this Form 10-K. The information required by Item 406 of Regulation S-K will be included under the caption “Corporate Governance Matters” in our 2005 Proxy Statement, and that information is incorporated by reference in this Form 10-K.

 

ITEM 11. EXECUTIVE COMPENSATION

 

The information required by Item 11 will be set forth in our 2005 Proxy Statement under the captions “Compensation of Directors,” “Compensation of Executive Officers” and “Employment Contracts,” and that information is incorporated by reference in this Form 10-K.

 

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

 

The information required by Item 12 will be set forth in our 2005 Proxy Statement under the captions “Beneficial Ownership of Voting Securities” and “Equity Compensation Plan Information,” and that information is incorporated by reference in this Form

10-K.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

Not applicable.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The information required by Item 14 will be set forth in our 2005 Proxy Statement under the captions “Audit Fees” and “Audit Committee Pre-Approval Policies and Procedures,” and that information is incorporated by reference in this Form 10-K.

 

PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

FINANCIAL STATEMENTS INCLUDED HEREIN

 

Westar Energy, Inc.

 

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets, as of December 31, 2004 and 2003

Consolidated Statements of Income (Loss) for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2004, 2003 and 2002

Notes to Consolidated Financial Statements

 

SCHEDULES

 

Schedule II - Valuation and Qualifying Accounts

 

Schedules omitted as not applicable or not required under the Rules of Regulation S-X: I, III, IV, and V

 

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EXHIBIT INDEX

 

All exhibits marked “I” are incorporated herein by reference. All exhibits marked by an asterisk are management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3) of Form 10-K. All exhibits marked “#” are filed with this Form 10-K.

 

Description

 

1(a)   -Underwriting Agreement between Westar Energy, Inc., and Citigroup Global Markets Inc. and Lehman Brothers Inc., as representatives of the several underwriters, dated January 12, 2005 (filed as Exhibit 1.1 to the January 18, 2005 Form 8-K)    I
3(a)   -By-laws of Westar Energy, Inc., as amended April 28, 2004 (filed as Exhibit 3(a) to June 30, 2004 Form 10-Q)    I
3(b)   -Restated Articles of Incorporation of Westar Energy, Inc., as amended through May 25, 1988 (filed as Exhibit 4 to Registration Statement, SEC File No. 33-23022)    I
3(c)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated March 29, 1991    I
3(d)   -Certificate of Designations for Preference Stock, 8.5% Series, without par value, dated March 31, 1991 (filed as Exhibit 3(d) to December 1993 Form 10-K)    I
3(e)   -Certificate of Correction to Restated Articles of Incorporation of Westar Energy, Inc. dated December 20, 1991 (filed as Exhibit 3(b) to December 1991 Form 10-K)    I
3(f)   -Certificate of Designations for Preference Stock, 7.58% Series, without par value, dated April 8, 1992, (filed as Exhibit 3(e) to December 1993 Form 10-K)    I
3(g)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 8, 1992 (filed as Exhibit 3(c) to December 31, 1994 Form 10-K)    I
3(h)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 26, 1994 (filed as Exhibit 3 to June 1994 Form 10-Q)    I
3(i)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 14, 1996 (filed as Exhibit 3(a) to June 1996 Form 10-Q)    I
3(j)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 12, 1998 (filed as Exhibit 3 to March 1998 Form 10-Q)    I
3(k)   -Form of Certificate of Designations for 7.5% Convertible Preference Stock (filed as Exhibit 99.4 to November 17, 2000 Form 8-K)    I
3(l)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated July 21, 1999 (filed as Exhibit 3(l) to the December 31, 2002 Form 10-K)    I
3(m)   -Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated June 19, 2002 (filed as Exhibit 3(m) to the December 31, 2002 Form 10-K)    I
4(a)   -Mortgage and Deed of Trust dated July 1, 1939 between Westar Energy, Inc. and Harris Trust and Savings Bank, Trustee (filed as Exhibit 4(a) to Registration Statement No. 33-21739)    I
4(b)   -First and Second Supplemental Indentures dated July 1, 1939 and April 1, 1949, respectively (filed as Exhibit 4(b) to Registration Statement No. 33-21739)    I
4(c)   -Sixth Supplemental Indenture dated October 4, 1951 (filed as Exhibit 4(b) to Registration Statement No. 33-21739)    I
4(d)   -Fourteenth Supplemental Indenture dated May 1, 1976 (filed as Exhibit 4(b) to Registration Statement No. 33-21739)    I
4(e)   -Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as Exhibit 4(o) to the December 1992 Form 10-K)    I
4(f)   -Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as Exhibit 4(p) to the December 1992 Form 10-K)    I
4(g)   -Thirtieth Supplemental Indenture dated February 1, 1993 (filed as Exhibit 4(q) to the December 1992 Form 10-K)    I
4(h)   -Thirty-First Supplemental Indenture dated April 15, 1993 (filed as Exhibit 4(r) to Registration Statement No. 33-50069)    I
4(i)   -Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as Exhibit 4(s) to the December 31, 1994 Form 10-K)    I
4(j)   -Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as Exhibit 4(v) to the December 31, 2000 Form 10-K)    I

 

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4(k)   -Thirty-Fifth Supplemental Indenture dated May 10, 2002 between Westar Energy, Inc. and BNY Midwest Trust Company, as Trustee (filed as Exhibit 4.1 to the March 31, 2002 Form 10-Q)    I
4(l)   -Thirty-Sixth Supplemental Indenture dated as of June 1, 2004, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the January 18, 2005 Form 8-K)    I
4(m)   -Thirty-Seventh Supplemental Indenture, dated as of June 17, 2004, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.2 to the January 18, 2005 Form 8-K)    I
4(n)   -Thirty-Eighth Supplemental Indenture, dated as of January 18, 2005, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.3 to the January 18, 2005 Form 8-K)    I
4(o)   -Forty-First Supplemental Indenture dated June 6, 2002 between Kansas Gas and Electric Company and BNY Midwest Trust Company, as Trustee (filed as Exhibit 4.1 to the June 30, 2002 Form 10-Q)    I
4(p)   -Forty-Second Supplemental Indenture dated March 12, 2004 between Kansas Gas and Electric Company and BNY Midwest Trust Company, as Trustee    #
4(q)   -Debt Securities Indenture dated August 1, 1998 (filed as Exhibit 4.1 to the June 30, 1998 Form 10-Q)    I
4(r)   -Securities Resolution No. 2 dated as of May 10, 2002 under Indenture dated as of August 1, 1998 between Western Resources, Inc. and Deutsche Bank Trust Company Americas (filed as Exhibit 4.2 to the March 31, 2002 Form 10-Q)    I
    Instruments defining the rights of holders of other long-term debt not required to be filed as Exhibits will be furnished to the Commission upon request.    I
10(a)   -Long-Term Incentive and Share Award Plan (filed as Exhibit 10(a) to the June 1996 Form 10-Q)*    I
10(b)   -Form of Employment Agreements with Messers. Lake and Wittig (filed as Exhibit 10(b) to the December 31, 2000 Form 10-K)*    I
10(c)   -A Rail Transportation Agreement among Burlington Northern Railroad Company, the Union Pacific Railroad Company and Westar Energy, Inc. (filed as Exhibit 10 to the June 1994 Form 10-Q)    I
10(d)   -Agreement between Westar Energy, Inc. and AMAX Coal West Inc. effective March 31, 1993 (filed as Exhibit 10(a) to the December 31, 1993 Form 10-K)    I
10(e)   -Agreement between Westar Energy, Inc. and Williams Natural Gas Company dated October 1, 1993 (filed as Exhibit 10(b) to the December 31, 1993 Form 10-K)    I
10(f)   -Short-term Incentive Plan (filed as Exhibit 10(k) to the December 31, 1993 Form 10-K)*    I
10(g)   -Westar Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended and restated, dated as of October 20, 2004 (filed as Exhibit 10(l) to the October 20, 2004 Form 8-K)*    I
10(h)   -Executive Salary Continuation Plan of Western Resources, Inc., as revised, effective September 22, 1995 (filed as Exhibit 10(j) to the December 31, 1995 Form 10-K)*    I
10(i)   -Letter Agreement between Westar Energy, Inc. and David C. Wittig, dated April 27, 1995 (filed as Exhibit 10(m) to the December 31, 1995 Form 10-K)*    I
10(j)   -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 to the June 30, 1998 Form 10-Q)*    I
10(k)   -Amendment to Letter Agreement between Westar Energy, Inc. and David C. Wittig, dated April 27, 1995 (filed as Exhibit 10 to the June 30, 1998 Form 10-Q/A)*    I
10(l)   -Letter Agreement between Westar Energy, Inc. and Douglas T. Lake, dated August 17, 1998 (filed as Exhibit 10(n) to the December 31, 1999 Form 10-K)*    I
10(m)   -Form of Change of Control Agreement with officers of Westar Energy, Inc. (filed as Exhibit 10(o) to the December 31, 2000 Form 10-K)*    I
10(n)  

-Form of loan agreement with officers of Westar Energy, Inc. (filed as Exhibit 10(r) to the December 31, 2001 Form

10-K)*

   I
10(o)   -Amendment to Employment Agreement dated April 1, 2002 between Westar Energy, Inc. and David C. Wittig (filed as Exhibit 10.1 to the June 30, 2002 Form 10-Q)*    I
10(p)   -Amendment to Employment Agreement dated April 1, 2002 between Westar Energy and Douglas T. Lake (filed as Exhibit 10.2 to the June 30, 2002 Form 10-Q)*    I
10(q)   -Credit Agreement dated as of June 6, 2002 among Westar Energy, Inc., the lenders from time to time party there to, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent (filed as Exhibit 10.3 to the June 30, 2002 Form 10-Q)    I

 

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10(r)   -Employment Agreement dated September 23, 2002 between Westar Energy, Inc. and David C. Wittig (filed as Exhibit 10.1 to the September 30, 2002 Form 10-Q)*    I
10(s)   -Employment Agreement dated September 23, 2002 between Westar Energy, Inc. and Douglas T. Lake (filed as Exhibit 10.1 to the November 25, 2002 Form 8-K)*    I
10(t)   -Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and James S. Haines, Jr. (filed as Exhibit 10(a) to the September 30, 2003 Form 10-Q)*    I
10(u)   -Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and William B. Moore (filed as Exhibit 10(b) to the September 30, 2003 Form 10-Q)*    I
10(v)   -Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Mark A. Ruelle (filed as Exhibit 10(c) to the September 30, 2003 Form 10-Q)*    I
10(w)   -Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Douglas R. Sterbenz (filed as Exhibit 10(d) to the September 30, 2003 Form 10-Q)*    I
10(x)   -Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Larry D. Irick (filed as Exhibit 10(e) to the September 30, 2003 Form 10-Q)*    I
10(y)   -Waiver and Amendment, dated as of November 6, 2003, to the Credit Agreement, dated as of June 6, 2002, among Westar Energy, Inc., the Lenders from time to time party thereto, JPMorgan Chase Bank, as Administrative Agent for the Lenders, Citibank, N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent (filed as Exhibit 10(f) to the September 30, 2003 Form 10-Q)    I
10(z)   -Credit Agreement dated as of March 12, 2004 among Westar Energy, Inc., the several banks and other financial institutions or entities from time to time parties to the Agreement, JPMorgan Chase Bank, as administrative agent, The Bank of New York, as syndication agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, National Association, as documentation agents (filed as Exhibit 10(a) to the March 31, 2004 Form 10-Q)    I
10(aa)   -Supplements and modifications to Credit Agreement dated as of March 12, 2004 among Westar Energy, Inc., as Borrower, the Several Lenders Party Thereto, JPMorgan Chase Bank, as Administrative Agent, The Bank of New York, as Syndication Agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, national Association, as Documentation Agents (filed as Exhibit 10(a) to the June 30, 2004 Form 10-Q)    I
10(ab)   -Purchase Agreement dated as of December 23, 2003 between POI Acquisition, L.L.C., Westar Industries, Inc. and Westar Energy, Inc. (filed as Exhibit 99.2 to the December 24, 2003 Form 8-K)    I
10(ac)   -Settlement Agreement dated November 12, 2004 by and among Westar Energy, Inc., Protection One, Inc., POI Acquisition, L.L.C., and POI Acquisition I, Inc. (filed as Exhibit 10.1 to the November 15, 2004 Form 8-K)    I
10(ad)   -Restricted Share Unit Award Agreement between Westar Energy, Inc. and James S. Haines, Jr. (filed as Exhibit 10.1 to the December 7, 2004 Form 8-K)    I
10(ae)   -Deferral Election Form of James S. Haines, Jr. (filed as Exhibit 10.2 to the December 7, 2004 Form 8-K)    I
10(af)   -Resolutions of the Westar Energy, Inc. Board of Directors regarding Non-Employee Director Compensation, approved on September 2, 2004 (filed as Exhibit 10.2 to the December 7, 2004 Form 8-K)    I
10(ag)   -Restricted Share Unit Award Agreement between Westar Energy, Inc. and William B. Moore (filed as Exhibit 10.1 to the December 29, 2004 Form 8-K)    I
10(ah)   -Deferral Election Form of William B. Moore (filed as Exhibit 10.2 to the December 29, 2004 Form 8-K)    I
12   -Computations of Ratio of Consolidated Earnings to Fixed Charges    #
21   -Subsidiaries of the Registrant    #
23   -Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP    #
31(a)   -Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002    #
31(b)   -Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002    #
32   -Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished and not to be considered filed as part of the Form 10-K)    #
99(a)   -Kansas Corporation Commission Order dated November 8, 2002 (filed as Exhibit 99.2 to the September 30, 2002 Form 10-Q)    I
99(b)   -Kansas Corporation Commission Order dated December 23, 2002 (filed as Exhibit 99.1 to the December 27, 2002 Form 8-K)    I

 

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99(c)   -Debt Reduction and Restructuring Plan filed with the Kansas Corporation Commission on February 6, 2003 (filed as Exhibit 99.1 to the February 6, 2003 Form 8-K)    I
99(d)  

-Kansas Corporation Commission Order dated February 10, 2003 (filed as Exhibit 99.1 to the February 11, 2003 Form

8-K)

   I
99(e)  

-Kansas Corporation Commission Order dated March 11, 2003 (filed as Exhibit 99(f) to the December 31, 2002 Form

10-K)

   I
99(f)   -Demand for Arbitration (filed as Exhibit 99.1 to the June 13, 2003 Form 8-K)    I
99(g)   -Stipulation and Agreement filed with the Kansas Corporation Commission on July 21, 2003 (filed as Exhibit 99.1 to the July 22, 2003 Form 8-K)    I

 

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WESTAR ENERGY, INC.

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

 

Description


  

Balance at

Beginning

of Period


  

Charged to
Costs and

Expenses


    Deductions

   

Balance

at End

of Period


          (In Thousands)      

Year ended December 31, 2002

                             

Allowances deducted from assets for doubtful accounts (a)

   $ 6,825    $ 6,266     $ (6,473 )   $ 6,618

Accrued exit fees, shut-down and severance costs (b)

     43      (43 )     —         —  

Year ended December 31, 2003

                             

Allowances deducted from assets for doubtful accounts (a)

     6,618      3,874       (5,077 )     5,415

Accrued exit fees, shut-down and severance costs

     —        —         —         —  

Year ended December 31, 2004

                             

Allowances deducted from assets for doubtful accounts

     5,415      2,718       (2,820 )     5,313

Accrued exit fees, shut-down and severance costs

     —        —         —         —  

(a) Deductions are the result of write-offs of accounts receivable.
(b) Deductions are the result of payment of accrued severance costs.

 

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SIGNATURE

 

Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

       

WESTAR ENERGY, INC.

Date: March 16, 2005

      By:   /s/ Mark A. Ruelle
               

Mark A. Ruelle,

Executive Vice President and

Chief Financial Officer

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature


  

Title


 

Date


/s/ JAMES S. HAINES, JR.


(James S. Haines, Jr.)

  

Director, Chief Executive Officer and President

(Principal Executive Officer)

  March 16, 2005

/s/ MARK A. RUELLE


(Mark A. Ruelle)

  

Executive Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

  March 16, 2005

/s/ CHARLES Q. CHANDLER IV


(Charles Q. Chandler IV)

  

Chairman of the Board

  March 16, 2005

/s/ MOLLIE H. CARTER


(Mollie H. Carter)

  

Director

  March 16, 2005

/s/ R. A. EDWARDS III


(R. A. Edwards III)

  

Director

  March 16, 2005

/s/ JERRY B. FARLEY


(Jerry B. Farley)

  

Director

  March 16, 2005

/s/ B. ANTHONY ISAAC


(B. Anthony Isaac)

  

Director

  March 16, 2005

/s/ ARTHUR B. KRAUSE


(Arthur B. Krause)

  

Director

  March 16, 2005

/s/ SANDRA A. J. LAWRENCE


(Sandra A. J. Lawrence)

  

Director

  March 16, 2005

/s/ MICHAEL F. MORRISSEY


(Michael F. Morrissey)

  

Director

  March 16, 2005

/s/ JOHN C. NETTELS, JR.


(John C. Nettels, Jr.)

  

Director

  March 16, 2005

 

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