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.
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.
ITEM 2. PROPERTIES
(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.
ITEM 3.
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.
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.
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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(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.
ITEM 7.
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.
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.
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.
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.
The tables below show fair value of energy marketing contracts outstanding for the year ended December 31, 2004, their sources and maturity periods.
The sources of the fair values of the financial instruments related to these contracts are summarized in the following table.
(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
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.
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.
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
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.
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.
(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.
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.
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.
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.
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
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.
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.
Debt Financings
During 2004, we made changes in our long-term debt as shown in the table below.
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.
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.
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.
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.
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.
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.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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.
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.
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
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
WESTAR ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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.
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.
• 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.
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.
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.
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.
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.
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.
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
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
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.
Results of discontinued operations are presented in the table below.
The major classes of assets and liabilities of the monitored services businesses were as follows.
5. ACCOUNTS RECEIVABLE AND VARIABLE INTEREST ENTITIES
Our accounts receivable on our consolidated balance sheets are comprised as follows.
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.
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.
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.
(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
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
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.
Depreciation expense on property, plant and equipment for the years ended December 31, 2004, 2003 and 2002 was as follows.
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.
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.
Information regarding our short-term borrowings is as follows.
Our interest expense on short-term debt was $1.1 million in 2004, $1.2 million in 2003 and $7.4 million in 2002.
11. LONG-TERM DEBT
Outstanding Debt
Long-term debt outstanding at December 31 is as follows.
(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
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.
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.
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.
(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.
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.”
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.
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.
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.
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.
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
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.
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.
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.
Stock options issued and outstanding at December 31, 2004 are as follows.
RSUs under the LTISA plan are as follows.
RSUs issued and outstanding at December 31, 2004 are as follows.
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.
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.
(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.
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.
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.
For measurement purposes, the assumed annual health care cost growth rates were as follows.
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.
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.
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.
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.
Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows.
Temporary differences related to deferred tax assets and deferred tax liabilities are summarized in the following table.
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.
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.
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.
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.
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.
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.
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.
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.
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
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
Any work force reductions since the completion of the 2002 voluntary separation have been in the normal course of operations.
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.
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.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
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.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
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.
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.
ITEM 12.
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
ITEM 14.
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.
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
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
WESTAR ENERGY, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(a) Deductions are the result of write-offs of accounts receivable.
(b) Deductions are the result of payment of accrued severance costs.
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.
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.