ITEM 1. BUSINESS
GENERAL
Kansas Gas and Electric Company is a regulated electric utility incorporated in 1990 in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “KGE,” “we,” “us,” “our” and similar words are to Kansas Gas and Electric Company.
We are a wholly owned subsidiary of Westar Energy, Inc. (Westar Energy) and we provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. We provide electric generation, transmission and distribution services to approximately 301,000 customers in south-central and southeastern Kansas, including the city of Wichita, Kansas. Our corporate headquarters is located in Wichita, Kansas.
We own 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
Refinancing of Debt
On June 10, 2004, we refinanced $327.5 million of pollution control bonds. The original issue had an interest rate of 7% and was due in 2031. This issue was replaced with pollution control bonds at interest rates of 5.3% on $127.5 million that mature in 2031, 2.65% on $100.0 million that are putable in 2006, and a variable rate on $100.0 million that mature in 2031.
OPERATIONS
General
We supply 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 24 Kansas cities and one electric cooperative. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities.
Generation Capacity
We have 2,587 megawatts (MW) of generating capacity. See “Item 2.
ITEM 2. PROPERTIES
ELECTRIC UTILITY FACILITIES
(a) We jointly own Jeffrey Energy Center (20%), LaCygne 1 generating unit (50%), and Wolf Creek Generating Station (47%). Westar Energy jointly owns 64% of Jeffrey Energy Center. Unit capacity amounts reflect our ownership only.
(b) In 1987, we entered into a sale-leaseback transaction involving our 50% interest in the LaCygne 2 generating unit.
We own approximately 2,200 miles of transmission lines, approximately 9,900 miles of overhead distribution lines and approximately 2,000 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
Information on our legal proceedings is set forth in Notes 3, 12, 14 and 15 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies - EPA New Source Review,” “Legal Proceedings,” and “Ongoing Investigations,” respectively, which are incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information required by Item 4 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our common stock is owned by Westar Energy and is not traded.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
We are a regulated electric utility in Kansas and a wholly owned subsidiary of Westar Energy. We provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. 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 goals for 2005 are to improve our business by improving 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
WCNOC calculates its pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by Statement of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively.
In accounting for WCNOC’s retirement plans and other post-retirement benefits, WCNOC makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of WCNOC’s pension benefit plan is impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine 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.
The following table shows the annual impact of a 0.5% decrease in our share of WCNOC’s 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 share of WCNOC’s 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 $25.0 million.
We are allocated a share of revenues from energy marketing derivative contracts that are jointly entered into with Westar Energy based on actual fuel burned at our generating facilities. The amount of actual fuel burned by a given generating facility is largely determined by utilizing the most economical units first. 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. 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.
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.
OPERATING RESULTS
We evaluate operating results based on income from operations. 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) financially settled products and physical transactions sourced outside our control area; and (2) 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.
(a) Transmission: Includes an SPP network transmission tariff. In 2004, our transmission costs were approximately $33.3 million. This amount, less $2.2 million that was retained by the SPP as administration cost, was returned to us as revenues. In 2003, our transmission costs were approximately $32.7 million with an administration cost of $2.9 million retained by the SPP.
(b) Fuel used for generation: Includes cost of fuel burned, changes in fair value of fuel contracts and net dispatch costs, which represent energy transactions allocated to us by Westar Energy.
The following table reflects changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity, for the two years ended December 31, 2004 and 2003. No sales volumes are shown for energy marketing, transmission or other.
Our residential and tariff-based wholesale customers used less energy and our sales volumes decreased because of cooler weather during the summer. When measured by cooling degree days, the weather during 2004 was 4% cooler than during 2003 and 9% below the 20-year average. We measure cooling degree days experienced in the Wichita metropolitan area, which 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 $4.0 million as compared to $1.7 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 $4.6 million of the increased market-based wholesale sales and higher average market prices accounted for approximately $5.0 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 used for generation decreased in 2004 due primarily to a reduction in fuel costs that were allocated to us by Westar Energy. In 2004, Wolf Creek did not have a scheduled refueling outage.
Purchased power expense increased due primarily to a 10% increase in volumes purchased during 2004 as compared to 2003. This was due to the unplanned outages or reduced operating capability of our units at certain times and the availability of economically priced power due to cooler weather in our region. At times, it was more economical to purchase power than to operate our available generating units.
Selling, general and administrative expenses increased in 2004, which reflects an increase in labor overheads allocated to us by Westar Energy. Operating and maintenance expenses increased due primarily to 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, increased operating costs at Wolf Creek and an increase in transmission costs. During 2004, increased maintenance of our generating units accounted for 14% of the increase in operating and maintenance expenses. The increase in distribution expenses accounted for 35% 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, Inc. shared services agreement as discussed in Note 17 of the Notes to Consolidated Financial Statements, “Related Party Transactions.” Wolf Creek operating costs increased 22% because it operated more during 2004 because Wolf Creek did not have a scheduled refueling outage as it did in 2003. An increase in transportation costs accounted for 9% of the increase in operating and maintenance expenses.
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 $32.7 million. This amount, less $2.9 million that was retained by the SPP as administration cost, was returned to us as revenues. In 2002, our transmission costs were approximately $32.9 million with an administration cost of $2.9 million retained by the SPP.
(b) Fuel used for generation: Includes cost of fuel burned, changes in fair value of fuel contracts and net dispatch costs allocated to us by Westar Energy.
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.
Our residential and tariff-based wholesale customers used less energy and our sales declined because of cooler weather. The remainder of the decline in retail sales revenues was due primarily to the decline in the accrual of approximately $1.7 million to be refunded to customers in 2005 and 2006 pursuant to a KCC order.
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.
Fuel used for generation decreased in 2003 due primarily to a reduction in fuel costs that were allocated to us by Westar Energy.
Selling, general and administrative expenses declined in 2003, which reflects a reduction in numerous incremental administrative expenses incurred in 2002 that were allocated to us for Westar Energy’s work force
reduction. Depreciation and amortization expense decreased due primarily to the adoption of new depreciation rates on April 1, 2002. Operating and maintenance expense increased due primarily to increased general maintenance expenses at our generating facilities.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital and maintenance expenditures designed to improve and maintain facilities that provide electric service and meet future customer service requirements. Our ability to provide the cash or debt to fund our capital expenditures depends on many things, including available resources, Westar Energy’s and our financial condition and current market conditions.
We expect our internally generated cash, advances from Westar Energy, availability of cash through Westar Energy’s credit facilities and access to capital markets to be sufficient to fund operations and debt service payments. We do not maintain independent short-term credit facilities and rely on Westar Energy for short-term cash needs. If Westar Energy is unable to borrow under its credit facilities, we could have a short-term liquidity problem that could require us to obtain a credit facility for our short-term cash needs and that could result in higher borrowing costs.
Capital Resources
Our mortgage contains provisions restricting the amount of first mortgage bonds that could be issued. Additionally, Westar Energy’s revolving credit facility prohibits us and Westar Energy 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.
Our mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless our 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 of our 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 first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
Westar Energy’s revolving credit facility prohibits us and Westar Energy 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. On January 18, 2005, Westar Energy sold $250.0 million aggregate principal amount of Westar Energy first mortgage bonds. Following this issuance, we and/or Westar Energy can incur a maximum of $25.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility.
Cash Flows from Operating Activities
Cash flows from operating activities decreased $3.4 million to $137.5 million in 2004 from $140.9 million in 2003. This decrease was mostly attributable to changes in working capital.
Cash Flows used in Investing Activities
In general, cash used for investing purposes relates to the growth and improvement of our utility operations. Our business is capital intensive and requires significant investment in plant on an annual basis. We spent $99.3 million in 2004, $90.2 million in 2003 and $65.2 million in 2002 on net additions to property, plant and equipment.
Cash Flows used in Financing Activities
Net cash used in financing activities totaled $25.5 million for the year ended December 31, 2004 as compared to $30.9 million for the year ended December 31, 2003. In 2004, cash was used for the retirement of long-term debt and to pay $75.0 million in dividends to Westar Energy. In 2003, cash was used to retire long-term debt and to pay $100.0 million in dividends to Westar Energy. Net cash used in financing activities totaled $81.9 million for the year ended December 31, 2002 due primarily to funds placed in a trust for long-term debt retirement.
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. We believe that internally generated funds, borrowings from Westar Energy and access to capital markets will be sufficient to meet our operating and capital expenditure requirements and debt service payments.
We are required to pay our share of the combined rebates to retail customers of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. We currently estimate we will be responsible for 47% of the rebate. Ultimate allocation will be determined by the KCC. Westar Energy and we believe we can fund these rebates with internally generated cash flow and available borrowing capacity under Westar Energy’s revolving credit facility.
If Westar Energy is required to update emissions controls or take other remedial action as a result of the EPA’s investigation of Westar Energy, the costs could be material. Westar Energy may also have to pay fines or penalties or make significant capital or operational expenditures related to the notice of violation Westar Energy 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. We anticipate that we would be allocated a portion of any of these potential costs. 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
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 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, Westar Energy 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 our first mortgage bonds.
On June 10, 2004, we refinanced $327.5 million of pollution control bonds. The original issue had an interest rate of 7% and was due in 2031. This issue was replaced with pollution control bonds at interest rates of 5.3% on $127.5 million that matures in 2031, 2.65% on $100.0 million that is putable in 2006, and a variable rate on $100.0 million that matures in 2031.
Debt Covenants
Some of Westar Energy’s debt instruments contain restrictions that require it to maintain various coverage and leverage ratios as defined in the agreements. Westar Energy calculates these ratios in accordance with its credit agreements. These ratios are used solely to determine compliance with its various debt covenants. Westar Energy was in compliance with these covenants at December 31, 2004.
Credit Ratings
Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service (Moody’s) and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate Westar Energy’s and our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our securities.
On February 23, 2005, Moody’s upgraded its ratings for our debt and affirmed the speculative liquidity rating it assigned to Westar Energy of SGL-2, reflecting its view that Westar Energy has “good” liquidity. On December 22, 2004, Fitch raised its outlook rating to positive from stable and affirmed its ratings as shown in the table below. On July 22, 2004, S&P improved its ratings on our first mortgage bonds to BBB from BB+.
As of March 1, 2005, ratings with these agencies are as shown in the table below.
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us. Westar Energy and we have credit rating conditions under our revolving credit agreement and in the agreements governing the sale of our accounts receivable discussed in Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities” that affect the cost of borrowing but do not trigger a default. We may enter into new credit agreements that contain credit conditions, which could affect our liquidity and/or our borrowing costs.
Capital Structure
Our consolidated capital structure at December 31, 2004 and 2003 was as follows.
OFF-BALANCE SHEET ARRANGEMENTS
Accounts Receivable Sales Program
Under a revolving accounts receivable sales program, we and Westar Energy can currently sell up to $125.0 million of our accounts receivable. For additional detail, see Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities.”
LaCygne 2 Sale/Leaseback Agreement
In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operating and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the lease term. See Note 16 of the Notes to Consolidated Financial Statements, “Operating Leases,” for additional information.
CONTRACTUAL CASH OBLIGATIONS
In the course of our business activities, we enter into a variety of contractual obligations. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements. The obligations listed below do not include amounts for on-going needs for which no contractual obligations existed at December 31, 2004, and represent only those amounts that we were contractually obligated to meet at December 31, 2004. We may from time to time enter into new contracts to replace contracts that expire.
The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2004.
OTHER INFORMATION
Ice Storm
On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric service in a large portion of our service territory and damaged a significant portion of our electric distribution system. We estimate that we will incur $31.0 million to $35.0 million of system restoration costs. Of this amount, we expect $5.5 million to $7.5 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.
Impact of Regulatory Accounting
We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings.
At December 31, 2004, we had recorded regulatory assets currently subject to recovery in future rates of approximately $321.4 million. Of this amount, $144.8 million is related to income tax benefits previously passed on to customers. The remainder of the regulatory assets include asset retirement obligations, system restoration, loss on reacquired debt, refinancing costs on the LaCygne 2 lease, deferred employee benefit costs, deferred plant costs and coal contract settlement costs. We periodically review SFAS No. 71 criteria and believe that our net regulatory assets are probable of future recovery.
Asset Retirement Obligations
In January 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Any income effects are offset by regulatory accounting pursuant to SFAS No. 71.
Legal Liability - Wolf Creek
On January 1, 2003, we recognized the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the present value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. We also established a regulatory asset for $64.0 million, which represents the accretion of the liability since 1985 and the increased depreciation expense associated with the increase in plant. The asset retirement obligation is included on our consolidated balance sheets in other long-term liabilities. Costs to retire Wolf Creek are currently being recovered through rates as provided by the KCC.
Non-legal Liability - Cost of Removal
We have recovered amounts in rates to provide for recovery of the probable costs of removing utility plant assets, but which do not represent legal retirement obligations. At December 31, 2004, we had $2.6 million in removal costs classified as a regulatory liability. At December 31, 2003, we had $2.1 million in removal costs classified as a regulatory asset. The net amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to removal costs incurred.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Hedging Activity
Westar Energy and we jointly 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 5 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.
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 are 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 18% 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 $2.0 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 21% increase, or $0.94 per MMBtu, in our average cost for natural gas purchased for utility operations. Due to this substantial increase in natural gas cost, we decreased our natural gas usage by approximately 1% compared to the amount burned in 2003. 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. Although the average cost for oil purchased for utility operations increased $0.59 per MMBtu, or approximately 19%, compared to the average cost in 2003, it was $1.66 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 $4.2 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 $211.4 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 $2.0 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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Kansas Gas and Electric Company
Topeka, Kansas
We have audited the accompanying consolidated balance sheets of Kansas Gas and Electric Company (the “Company”), a wholly-owned subsidiary of Westar Energy, Inc., as of December 31, 2004 and 2003, and the related consolidated statements of income and comprehensive income, shareholder’s 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. The Company is not required to have, nor were we engaged to perform, an audit of internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 as of December 31, 2004 and 2003, and the results of its operations and its 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 13 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations.”
DELOITTE & TOUCHE LLP
Kansas City, Missouri
March 11, 2005
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
Kansas Gas and Electric Company is a regulated electric utility incorporated in 1990 in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “KGE,” “we,” “us,” “our” and similar words are to Kansas Gas and Electric Company. We are a wholly owned subsidiary of Westar Energy, Inc. (Westar Energy) and we provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. We provide electric generation, transmission and distribution services to approximately 301,000 customers in south-central and southeastern Kansas, including the city of Wichita, Kansas. Our corporate headquarters is located in Wichita, Kansas.
We own 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 our undivided interests in jointly-owned generation facilities on a pro rata basis. 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, valuation of our energy marketing portfolio, intangible assets, income taxes, our portion of WCNOC’s pension and other post-retirement benefits, our asset retirement obligations including decommissioning of Wolf Creek, 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.
•
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 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.
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 3.8% in 2004, 5.3% in 2003 and 6.0% in 2002. The cost of additions to utility plant and replacement units of property is capitalized. AFUDC capitalized was $1.1 million in 2004, $0.9 million in 2003 and $1.0 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 2.2% during 2004, 2.2% during 2003 and 2.4% during 2002.
Effective April 1, 2002, we adopted new depreciation rates which reduced our annual depreciation expense by approximately $18.0 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 approximated $0.8 million in 2004, $0.2 million in 2003 and $2.1 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 total billed sales. At December 31, 2004, we had estimated unbilled revenue of $25.0 million.
We are allocated a share of revenues from energy marketing derivative contracts that are jointly entered into with Westar Energy based on actual fuel burned at our generating facilities. The amount of actual fuel burned by a given generating facility is largely determined by utilizing the most economical units first. 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. 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.
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.
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, Westar Energy and 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.
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. 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 of Westar Energy, 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 $1.3 million in 2002. We include these expenses in other expense on our consolidated statements of income.
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. The provisions of this interpretation became effective upon issuance. We were not affected by FIN 46R.
5. 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.
Westar Energy and we jointly 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. 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, Westar Energy and we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases. Initially, Westar Energy entered into futures and swap contracts with terms extending through July 2004 to hedge price risk for a portion of anticipated natural gas fuel requirements for generation facilities. We designated these hedging relationships as cash flow hedges.
In 2002, due to the increased availability of 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 8,280,000 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 $2.8 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 $1.8 million.
6. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31.
Depreciation expense on property, plant and equipment was $71.7 million in 2004, $70.5 million in 2003 and $73.8 million in 2002.
7. JOINT OWNERSHIP OF UTILITY PLANTS
Under joint ownership agreements with other utilities, we have undivided ownership interests in three 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.
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with Aquila, Inc. and Westar Energy.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
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 us in 1987, are included in operating expenses on our consolidated statements of income. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.
8. SHORT-TERM BORROWINGS
We had no short-term borrowings outstanding at December 31, 2004 and 2003. Our short-term liquidity needs are met from cash advances by Westar Energy.
Westar Energy has an arrangement with a syndicate of banks to provide it a revolving credit facility on a committed basis totaling $300.0 million. The facility is secured by our first mortgage bonds and matures on March 12, 2007.
See Note 9, “Long-term Debt,” for a discussion of covenants applicable to Westar Energy’s credit facilities.
9. LONG-TERM DEBT
The amount of our first mortgage bonds authorized by our Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2.0 billion. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions of the Mortgage. Electric plant is subject to the lien of the Mortgage except for transportation equipment. At December 31, 2004, based on an assumed interest rate of 6%, approximately $874.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
Long-term debt outstanding at December 31 is as follows.
(a) We amortize debt discount over the term of the respective issue.
Debt Covenants
Some of Westar Energy’s debt instruments contain restrictions that require it to maintain various coverage and leverage ratios as defined in the agreements. Westar Energy calculates these ratios in accordance with its credit agreements. These ratios are used solely to determine compliance with its various debt covenants. Westar Energy was 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 $29.6 million in 2004, $46.5 million in 2003 and $46.8 million in 2002.
10. 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 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. 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.
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.
Expected cash flows
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.
11. 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 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.
We are a member of Westar Energy’s consolidated tax group. We file consolidated tax returns with Westar Energy. Westar Energy allocates to us our pro rata portion of consolidated income taxes based on our contribution to consolidated taxable income.
As of December 31, 2004, we had recorded reserves for uncertain tax positions, including interest, of $2.9 million. 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 $0.5 million (after-tax) for property and sales tax assessments by various state and local taxing authorities.
12. 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 $22.0 million at December 31, 2004, all of which has been committed. These commitments relate 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 Westar Energy under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants it operates. On January 22, 2004, the EPA notified Westar Energy that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.
Westar Energy is in discussions with the EPA concerning this matter in an attempt to reach a settlement. Westar Energy expects that any settlement with the EPA could require Westar Energy to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years. Additionally, Westar Energy might be required to update or install emissions controls at its other coal-fired plants, pay fines or penalties, or take other remedial action. Together, these costs could be material. The EPA informed Westar Energy 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 Westar Energy were to reach a settlement with the EPA, Westar Energy may be assessed a penalty. The penalty could be material and may not be recovered in rates. We anticipate that a portion of any of these potential costs would be allocated to us.
Manufactured Gas Sites
We have been associated with three former manufactured gas sites located in Kansas that may contain coal tar and other potentially harmful materials. We and the Kansas Department of Health and Environment entered into a consent agreement in 1994 governing all future work at these sites. Through December 31, 2004, the costs incurred for preliminary site investigation and risk assessment have been minimal.
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 $354.5 million. 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 $1.1 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 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.
13. 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, we had $2.6 million in removal costs classified as a regulatory liability. At December 31, 2003, we had $2.1 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.
14. LEGAL PROCEEDINGS
We are involved in various 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, 12, and 15 for discussion of KCC regulatory proceedings, alleged violations of the Clean Air Act and an investigation by FERC.
15. ONGOING INVESTIGATIONS
FERC Subpoena
On December 16, 2002, Westar Energy 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. Westar Energy has provided information to FERC in response to the original subpoena, subsequent requests submitted through its 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. Westar Energy believes that our participation in these transactions and the conduct of its generation and transmission operations did not violate FERC rules and regulations. However, Westar Energy is unable to predict the ultimate outcome of the investigation.
16. 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.
(a) The LaCygne 2 lease amounts are included in the total operating leases column above.
In 1987, we sold and leased back our 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. We remain responsible for our 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.
17. RELATED PARTY TRANSACTIONS
Our cash management function, including cash receipts and disbursements, is performed by Westar Energy. An intercompany account is used to record receipts and disbursements between Westar Energy and us. The net amount payable to affiliates was approximately $91.5 million at December 31, 2004 and approximately $81.4 million at December 31, 2003 as reflected on our consolidated balance sheets.
Westar Energy provides all employees we use. Certain operating expenses have been allocated to us from Westar Energy. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers and/or other appropriate factors. We believe such allocation procedures are reasonable.
We declared and paid dividends of $75.0 million to Westar Energy for the year ended December 31, 2004 and $100.0 million for the year ended December 31, 2003. There were no dividends declared or paid in 2002.
Termination of Shared Services Agreement
Westar Energy previously maintained shared services agreements with ONEOK, Inc. (ONEOK) pursuant to which Westar Energy and ONEOK provide customer service functions to each other, including meter reading, customer billing and call center operations. 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, Westar Energy and ONEOK plan to continue to share some facilities and a mobile communications system.
18. QUARTERLY RESULTS (UNAUDITED)
Our 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.
19. 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 $31.0 million to $35.0 million of system restoration costs. Of this amount, we expect $5.5 million to $7.5 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
We are a wholly owned subsidiary of Westar Energy and all evaluations of our controls and procedures were conducted in conjunction with those undertaken by Westar Energy. Under the supervision and with the participation of Westar Energy’s management, including our president and our principal financial and accounting 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 president and our principal financial and accounting 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.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Independent Auditor Fees
The aggregate fees billed by our principal accounting firm, Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”) for services provided for fiscal years ended December 31, 2004 and 2003 are as follows.
Audit Committee Pre-Approval Policies and Procedures
Westar Energy’s Audit Committee charter provides that the Audit Committee will pre-approve audit services and non-audit services to be provided by our independent auditors before the accountant is engaged to render these services. Westar Energy’s Audit Committee may consult with management in the decision-making process, but may not delegate this authority to management. Westar Energy’s Audit Committee may delegate its authority to pre-approve services to one or more committee members, provided that the designees present the pre-approvals to the full committee at the next committee meeting.
Westar Energy’s Audit Committee has authorized the Chairman of the Audit Committee to pre-approve the retention of an independent auditor for audit-related and permitted non-audit services not contemplated by the engagement letter for the annual audit, provided that: (a) these services are approved no more than thirty days in advance of the auditor commencing work; (b) the fees to be paid to the auditor for services related to any single engagement do not exceed $25,000; (c) the aggregate fees to be paid to the auditor for services in any calendar year do not exceed $100,000; and (d) the Chairman advises the Audit Committee of the pre-approval of the services at the next meeting of the Audit Committee following the approval.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENTS INCLUDED HEREIN
Kansas Gas and Electric Company
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, as of December 31, 2004 and 2003
Consolidated Statements of Income and Comprehensive Income, 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 Shareholder’s 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.
Description
KANSAS GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(a) Deductions are primarily the result of write-offs of accounts receivable.
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.