ITEM 1. BUSINESS
GENERAL
Westar Energy, Inc., a Kansas corporation incorporated in 1924, operates the largest electric utility in Kansas and owns interests in monitored security businesses and other investments. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” or similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc. alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 647,000 customers in Kansas. We also provide monitored security services to over 1.1 million customers in the United States and Europe. ONEOK, Inc. (ONEOK), in which we presently own an approximate 27.5% interest (we owned an approximate 45% interest at December 31, 2002; see “- Changes in ONEOK Ownership” below), provides natural gas transmission and distribution services to approximately 1.9 million customers in Kansas, Oklahoma and Texas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.
Westar Energy and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek), our nuclear powered generating facility.
Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK and our other non-utility businesses. Protection One, a publicly traded, approximately 88%-owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns an approximate 99.8% interest.
SIGNIFICANT BUSINESS DEVELOPMENTS
Overview
A number of significant developments have impacted us and our business operations since January 2002.
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We hired a new chief executive officer and senior management team.
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We filed a new Debt Reduction and Restructuring Plan (the Debt Reduction Plan) with the Kansas Corporation Commission (KCC) that reflects our decision to return to being exclusively a Kansas electric utility, replacing an earlier plan that contemplated the separation of Westar Industries.
•
We began implementing the Debt Reduction Plan by (a) selling a portion of our ONEOK preferred stock, exchanging the remaining preferred stock for a new class of ONEOK preferred stock and modifying our related agreements with ONEOK, (b) reducing our first quarter 2003 dividend 37% to $0.19 per share, and (c) exploring alternatives for the disposition of our interests in Protection One and Protection One Europe.
•
In May and June 2002, we refinanced approximately $1.3 billion of outstanding debt.
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A Special Committee of our board of directors, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC) and a federal grand jury initiated investigations into various matters.
•
We recorded impairment charges related to our monitored security businesses of approximately $864.9 million, net of tax benefit and minority interests, of which $671.0 million was related to goodwill and $193.9 million was related to customer accounts.
•
We repurchased a portion of our 6.25% senior unsecured notes that have a final maturity of August 15, 2018 and are putable and callable on August 15, 2003 (the putable/callable notes). As a result, we recognized a loss related to the fair value of a call option associated with the putable/callable notes for 2002 of $23.7 million, net of a $15.7 million tax benefit.
•
We reduced our utility work force by approximately 400 employees through a voluntary separation program.
•
We restored service from a severe ice storm in late January 2002 and incurred $19.3 million for restoration costs, a portion of which was capitalized.
•
ONEOK gave us notice of termination effective December 2003 of a shared services agreement pursuant to which we provide customer service functions to each other, including meter reading, customer billing and call center operations. We expect termination of this agreement will increase our annual costs to provide these services by approximately $11 million to $13 million.
New Chief Executive Officer and Senior Management Team
James S. Haines, Jr., joined us in December 2002 as our chief executive officer and president and a member of the board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with us and our affiliates. Mr. Wittig had been on administrative leave without pay since November 7, 2002 as a result of his indictment by a federal grand jury in Topeka, Kansas, for actions arising from his personal dealings.
Mr. Haines added new members to our senior management team, including William B. Moore as executive vice president and chief operating officer, and Mark A. Ruelle as executive vice president and chief financial officer. All of these officers were previously employed with us and have a strong background in the electric utility business. Douglas T. Lake, our executive vice president and chief strategic officer, resigned as a member of the board of directors and was placed on unpaid leave from all of his other positions with us and our affiliates on December 6, 2002.
See Note 35 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about our potential liabilities to Mr. Wittig and Mr. Lake.
KCC Orders and Debt Reduction and Restructuring Plan
On February 6, 2003, we filed the Debt Reduction Plan with the KCC outlining our plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of our non-utility assets, including our interests in Protection One, Protection One Europe and ONEOK. As part of the Debt Reduction Plan, the first quarter 2003 dividend on our common stock was reduced 37% to $0.19 per share. In addition, the Debt Reduction Plan contemplates the potential issuance of additional Westar Energy equity, if needed to further reduce debt following the disposition of all material non-utility assets. On February 10, 2003, the KCC issued an order in which it stated that the Debt Reduction Plan appears to make a good-faith effort to address the concerns expressed in the KCC’s prior orders and that the KCC needed additional time to review the Debt Reduction Plan prior to addressing other issues. The KCC also stayed the requirement of a December 23, 2002 order that we form a utility-only subsidiary for our former KPL electric utility division (KPL) no later than August 1, 2003.
The Debt Reduction Plan replaced a previous financial plan to which we devoted extensive efforts throughout 2002 to obtain KCC approval. This plan contemplated the sale of Westar Industries common stock in a rights offering. We refer you to our Annual Report on Form 10-K for the year ended December 31, 2001 and subsequent Quarterly Reports on Form 10-Q for further information on this financial plan and related KCC orders. The KCC rejected this plan on November 8, 2002 and issued an order that directed us to file a new financial plan, to reverse specified intercompany transactions, to reduce debt by $100 million annually in each of the next two years from internally generated cash flow, and to restructure our organizational structure so that KPL would be placed in a separate subsidiary with the amount of debt held by the utility not exceeding $1.47 billion. The order further established standstill protections requiring that we seek KCC approval before we enter into certain transactions with a non-utility affiliate. Following our filing of a motion for reconsideration and clarification of this order, the KCC
issued an order on December 23, 2002 directing that no later than August 1, 2003, KPL be held within a separate utility-only subsidiary and that the consolidated debt for all of our utility businesses not exceed $1.67 billion.
The standstill provisions of the December 23, 2002 KCC order potentially could have had a material adverse impact on Protection One. These standstill provisions are described in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.” On March 11, 2003, the KCC issued an order permitting us to make the payment due to Protection One in 2003 under a tax sharing agreement and to continue making loans to Protection One under a revolving credit facility. In addition, the order permitted us to reimburse Protection One approximately $4.4 million for information technology and aviation services, subject to certain conditions.
The KCC staff and other parties to the KCC docket considering the Debt Reduction Plan have filed comments on the Debt Reduction Plan. The KCC has not yet established a procedural schedule for considering the Debt Reduction Plan and the related comments. We are unable to predict what action the KCC will take with respect to the Debt Reduction Plan.
The KCC Orders dated November 8, 2002, December 23, 2002, February 10, 2003 and March 11, 2003 and the Debt Reduction Plan are exhibits to this Annual Report on Form 10-K. All of such exhibits are incorporated by reference herein. All of the documents concerning these matters, including the KCC Orders, can also be reviewed at the website of the KCC at www.kcc.state.ks.us (the website information is not incorporated herein or otherwise made a part of this Annual Report on Form 10-K). We refer you to these documents for further information concerning these matters.
Changes in ONEOK Ownership
On February 5, 2003, ONEOK repurchased from Westar Industries 9,038,755 shares of its Series A Convertible Preferred Stock, which were convertible into 18,077,511 shares of common stock. We received $300 million as a result of this sale, which was previously approved by the KCC. We anticipate using all or a portion of the net proceeds to repurchase or provide for the repayment of all of the putable/callable notes and a portion of our 6.875% senior unsecured notes.
Westar Industries also exchanged its remaining shares of Series A Convertible Preferred Stock for 21,815,386 new shares of ONEOK’s Series D Convertible Preferred Stock. ONEOK has agreed to file a shelf registration statement covering the Series D Convertible Preferred and common stock held by Westar Industries. Future sales will be subject to various conditions including the effectiveness of such registration, the required waiver or expiration of a 180-day lock-up period ending on July 22, 2003, and future market conditions. As of March 14, 2003, Westar Industries holds an approximate 27.5% ownership interest in ONEOK, assuming conversion of the Series D Convertible Preferred Stock.
In 2002 and prior periods, we accounted for our ONEOK common stock investment under the equity method of accounting. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and mark to market its fair value through other comprehensive income. We will begin accounting for our ONEOK Series D Convertible Preferred Stock investment under this method if and when a public market for these securities develops.
Sale of Protection One and Protection One Europe
On January 13, 2003, we announced that our board of directors authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe. The Debt Reduction Plan provides for the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. As a result, these operations were classified as discontinued operations during the first quarter of 2003 pursuant to the provisions of SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.”
As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount, which could be material, by which our basis exceeds the estimated fair value.
We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.
Ongoing Investigations
Grand Jury Subpoena
On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and the company in general. We are providing information in response to these requests and are fully cooperating in the investigation. We have not been informed that we are a target of the investigation. We are unable to predict the ultimate outcome of the investigation or its impact on us.
Securities and Exchange Commission Inquiry
On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these matters and other matters within the scope of the grand jury investigation. We are unable to predict the ultimate outcome of the inquiry or its impact on us.
Special Committee Investigation
Our board of directors appointed a Special Committee of directors to investigate management matters and matters that are the subject of the grand jury investigation and SEC inquiry. The Special Committee retained counsel and other advisors. The Special Committee investigation has been completed and has not resulted in adjustments to our consolidated financial statements.
FERC Subpoena
On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation (Cleco) and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries.
We have provided information to FERC in response to the subpoena. We believe that our participation in these transactions did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation. See Note 19 of the Notes to Consolidated Financial Statements, “Ongoing Investigations - FERC Subpoena,” for additional information.
Call Option
In August 1998, we entered into a call option with an investment bank related to the issuance of $400 million of our putable/callable notes. This call option is required to be settled by August 2003 through either a cash payment or a remarketing or refinancing of the putable/callable notes. The ultimate value of the call option will be based on the difference between the 10-year United States treasury rate on August 12, 2003 and 5.44%. If the 10-year United States treasury rate on August 12, 2003 is less than 5.44%, we will have a liability to the investment bank at that time. At December 31, 2002, our potential liability under the call option was $62.2 million. Based on the 10-year forward treasury rate on March 14, 2003 of 3.91%, we would be obligated to make a cash payment of approximately $69.1 million to settle the call option if we did not remarket or refinance the notes. The amount of
our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. If settled through a remarketing or refinancing, any liability related to the call option will be amortized as a credit to interest expense over the term of the new debt. The investment bank will price the notes to yield a market premium adequate to allow the investment bank to retain proceeds equal to the fair value of the call option at settlement.
At the time of issuance of the notes in 1998, we were not required by generally accepted accounting principles (GAAP) to account separately for the call option. However, when we began retiring these notes as a part of our overall debt reduction strategy, the portion of the call option associated with the retired notes became a free-standing option required to be treated as a derivative instrument under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). In addition, under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our balance sheet reflects the current fair value of the free standing portion of the call option. For 2002, we recognized a loss of $10.1 million, net of $6.7 million tax benefit, related to the fair value of the call option associated with the putable/callable notes at the time the notes were retired. This loss is included in our consolidated statements of income as part of the gain on extinguishment of debt line item of other income. For 2002, we also recorded an additional non-cash charge of $13.6 million, net of $9.0 million tax benefit, to reflect mark to market changes in the fair value of the call option associated with the retired notes. This charge is reflected in the other line item of other income in our consolidated statements of income. In total, the loss recorded related to the fair value of the call option for the year ended December 31, 2002 was $23.7 million, net of $15.7 million tax benefit.
We intend to repurchase or provide for the repayment of the putable/callable notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. From January 1, 2003 through March 14, 2003, we purchased $35.3 million face value of our putable/callable notes. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.
Impairment Charges
Effective January 1, 2002, we adopted SFAS No. 142, “Accounting for Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” As a result of implementing the new standards, we recorded a charge for the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.
In addition, in the fourth quarter of 2002 we recorded a $79.7 million impairment charge, net of tax benefit and minority interests, to reflect the additional impairment of all remaining goodwill of Protection One’s North America segment. We also recorded a $36 million impairment charge to reflect the impairment of all remaining goodwill at Protection One Europe. These accounting standards, the related charges and other related information are discussed in Note 23 of the Notes to Consolidated Financial Statements, “Impairment Charges.”
Work Force Reductions
During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We recorded a net charge of approximately $21.7 million in 2002 related to this program. We have replaced and may continue to replace some of these employees. For additional information, see Note 29 of the Notes to Consolidated Financial Statements, “Work Force Reductions.”
Ice Storm
In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. Through December 31, 2002, we incurred $19.3 million for restoration costs, a portion of which was capitalized. We have deferred and recorded as a regulatory asset on our December 31, 2002 consolidated balance sheet restoration costs of approximately $15.0 million. We have received an accounting authority order from the KCC that allows us to accumulate and defer for potential future recovery all operating and carrying costs related to storm restoration.
ELECTRIC UTILITY OPERATIONS
General
We supply electric energy at retail to approximately 647,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We classify our customers as residential, commercial and industrial as defined in our tariffs. We also supply electric energy at wholesale to the electric distribution systems of 62 Kansas cities and four rural electric cooperatives. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we have power marketing operations that purchase and sell electricity in areas outside our historical service territory.
Our electric sales for the three years ended December 31 were as follows:
The following tables show changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity we generate, for the three years ended December 31. No sales volumes are shown for network integration or power marketing because these activities are not related to electricity we generate.
Generation Capacity
We have 5,929 megawatts (MW) of generating capacity. See “Item 2.
ITEM 2. PROPERTIES
ELECTRIC UTILITY FACILITIES
(a)
We jointly own Jeffrey Energy Center (84%), LaCygne 1 generating unit (50%), Wolf Creek Generating Station (47%) and State Line (40%). Unit capacity amounts reflect Westar Energy’s ownership only.
(b)
In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the LaCygne 2 generating unit.
We own approximately 6,600 miles of transmission lines, approximately 27,000 miles of overhead distribution lines and approximately 3,000 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.
MONITORED SERVICES FACILITIES
Protection One maintains its executive offices at 818 South Kansas Avenue, Topeka, Kansas, 66612. Protection One and Protection One Europe operate primarily from the above facilities, although Protection One also leases office space for approximately 60 service branch offices and seven satellite branches in the United States and Protection One Europe leases offices for approximately 31 sales branch offices in continental Europe.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Information on our legal proceedings is set forth in Notes 3, 18, 19 and 35 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Legal Proceedings,” “Ongoing Investigations,” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2002.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of March 14, 2003, there were 33,334 common shareholders of record. For information regarding quarterly common stock price ranges for 2002 and 2001, see Note 33 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”
DIVIDENDS
Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, dividends must first be paid to the holders of preferred stock based on the fixed dividend rate for each series, and our obligations with respect to mandatorily redeemable preferred securities issued by subsidiary trusts must be met.
Quarterly dividends on common stock and preferred stock normally are paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, regulation, including the KCC’s order requiring us to reduce our outstanding debt, competition and financial loan covenants. In February 2003, we declared a first-quarter 2003 dividend of $0.19 per share. Our Articles of Incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We provide further information on these restrictions in Note 20 of the Notes to Consolidated Financial Statements, “Common Stock, Preferred Stock and Other Mandatorily Redeemable Securities.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Cash Requirements,” Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation” and Note 20, “Common Stock, Preferred Stock and Other Mandatorily Redeemable Securities,” included herein for additional information on dividends.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The information called for by the item relating to “Securities Authorized for Issuance Under Equity Compensation Plans” will be set forth under that heading in the Proxy Statement relating to the Annual Meeting of Shareholders to be held June 16, 2003, which will be filed with the Securities and Exchange Commission no later than April 30, 2003, and which is incorporated herein by reference. See also “Item 12. Security Ownership of Certain Beneficial Owners and Management.”
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(a)
See Note 23 of the Notes to Consolidated Financial Statements, “Impairment Charges.”
(b)
Information reflects the impairment of marketable securities and the change to an accelerated amortization method for the monitored services segment’s customer accounts.
(c)
Information reflects exit costs associated with international power development activities.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In Management’s Discussion and Analysis, we discuss the general financial condition, significant annual changes and the operating results for us and our subsidiaries. We explain:
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what factors impact our business,
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what our earnings and costs were in 2002, 2001 and 2000,
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why these earnings and costs differ from year to year,
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how our earnings and costs affect our overall financial condition,
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what our capital expenditures were for 2002,
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what we expect our capital expenditures to be for the years 2003 through 2005,
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how we plan to pay for these future capital expenditures,
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critical accounting policies, and
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any other items that particularly affect our financial condition or earnings.
As you read Management’s Discussion and Analysis, please refer to our consolidated financial statements and the accompanying notes, which show our operating results.
SUMMARY OF SIGNIFICANT ITEMS
Overview
A number of significant developments have impacted us and our business operations since January 2002.
•
We hired a new chief executive officer and senior management team.
•
We filed a new Debt Reduction and Restructuring Plan (the Debt Reduction Plan) with the Kansas Corporation Commission (KCC) that reflects our decision to return to being exclusively a Kansas electric utility, replacing an earlier plan that contemplated the separation of Westar Industries, Inc. (Westar Industries).
•
We began implementing the Debt Reduction Plan by (a) selling a portion of our ONEOK, Inc. (ONEOK) preferred stock, exchanging the remaining preferred stock for a new class of ONEOK preferred stock and modifying our related agreements with ONEOK, (b) reducing our first quarter 2003 dividend 37% to $0.19 per share, and (c) exploring alternatives for the disposition of our interests in Protection One, Inc. (Protection One) and Protection One Europe.
•
In May and June 2002, we refinanced approximately $1.3 billion of outstanding debt.
•
A Special Committee of our board of directors, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC) and a federal grand jury initiated investigations into various matters.
•
We recorded impairment charges related to our monitored security businesses of approximately $864.9 million, net of tax benefit and minority interests, of which $671.0 million was related to goodwill and $193.9 million was related to customer accounts.
•
We repurchased a portion of our 6.25% senior unsecured notes that have a final maturity of August 15, 2018 and are putable and callable on August 15, 2003 (the putable/callable notes). As a result, we recognized a loss related to the fair value of a call option associated with the putable/callable notes for 2002 of $23.7 million, net of a $15.7 million tax benefit.
•
We reduced our utility work force by approximately 400 employees through a voluntary separation program.
•
We restored service from a severe ice storm in late January 2002 and incurred $19.3 million for restoration costs, a portion of which was capitalized.
•
ONEOK gave us notice of termination effective December 2003 of a shared services agreement pursuant to which we provide customer service functions to each other, including meter reading, customer billing and call center operations. We expect termination of this agreement will increase our annual costs to provide these services by approximately $11 million to $13 million.
New Chief Executive Officer and Senior Management Team
James S. Haines, Jr., joined us in December 2002 as our chief executive officer and president and a member of the board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with us and our affiliates. Mr. Wittig had been on administrative leave without pay since November 7, 2002 as a result of his indictment by a federal grand jury in Topeka, Kansas, for actions arising from his personal dealings.
Mr. Haines added new members to our senior management team, including William B. Moore as executive vice president and chief operating officer, and Mark A. Ruelle as executive vice president and chief financial officer. All of these officers were previously employed with us and have a strong background in the electric utility business. Douglas T. Lake, our executive vice president and chief strategic officer, resigned as a member of the board of directors and was placed on unpaid leave from all of his other positions with us and our affiliates on December 6, 2002.
See Note 35 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about our potential liabilities to Mr. Wittig and Mr. Lake.
KCC Orders and Debt Reduction and Restructuring Plan
On February 6, 2003, we filed the Debt Reduction Plan with the KCC outlining our plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of our non-utility assets, including our interests in Protection One, Protection One Europe and ONEOK. As part of the Debt Reduction Plan, the first quarter 2003 dividend on our common stock was reduced 37% to $0.19 per share. In addition, the Debt Reduction Plan contemplates the potential issuance of additional Westar Energy equity, if needed to further reduce debt following the disposition of all material non-utility assets. On February 10, 2003, the KCC issued an order in which it stated that the Debt Reduction Plan appears to make a good-faith effort to address the concerns expressed in the KCC’s prior orders and that the KCC needed additional time to review the Debt Reduction Plan prior to addressing other issues. The KCC also stayed the requirement of a December 23, 2002 order that we form a utility-only subsidiary for our former KPL electric utility division (KPL) no later than August 1, 2003.
The Debt Reduction Plan replaced a previous financial plan to which we devoted extensive efforts throughout 2002 to obtain KCC approval. This plan contemplated the sale of Westar Industries common stock in a rights offering. We refer you to our Annual Report on Form 10-K for the year ended December 31, 2001 and subsequent Quarterly Reports on Form 10-Q for further information on this financial plan and related KCC orders. The KCC rejected this plan on November 8, 2002 and issued an order that directed us to file a new financial plan, to reverse specified intercompany transactions, to reduce debt by $100 million annually in each of the next two years from internally generated cash flow, and to restructure our organizational structure so that KPL would be placed in a separate subsidiary with the amount of debt held by the utility not exceeding $1.47 billion. The order further established standstill protections requiring that we seek KCC approval before we enter into certain transactions with a non-utility affiliate. Following our filing of a motion for reconsideration and clarification of this order, the KCC issued an order on December 23, 2002 directing that no later than August 1, 2003, KPL be held within a separate utility-only subsidiary and that the consolidated debt for all of our utility businesses not exceed $1.67 billion.
The standstill provisions of the December 23, 2002 KCC order potentially could have had a material adverse impact on Protection One. These standstill provisions are described in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.” On March 11, 2003, the KCC issued an order permitting us to
make the payment due to Protection One in 2003 under a tax sharing agreement and to continue making loans to Protection One under a revolving credit facility. In addition, the order permitted us to reimburse Protection One approximately $4.4 million for information technology and aviation services, subject to certain conditions.
The KCC staff and other parties to the KCC docket considering the Debt Reduction Plan have filed comments on the Debt Reduction Plan. The KCC has not yet established a procedural schedule for considering the Debt Reduction Plan and the related comments. We are unable to predict what action the KCC will take with respect to the Debt Reduction Plan.
The KCC Orders dated November 8, 2002, December 23, 2002, February 10, 2003 and March 11, 2003 and the Debt Reduction Plan are exhibits to this Annual Report on Form 10-K. All of such exhibits are incorporated by reference herein. All of the documents concerning these matters, including the KCC Orders, can also be reviewed at the website of the KCC at www.kcc.state.ks.us (the website information is not incorporated herein or otherwise made a part of this Annual Report on Form 10-K). We refer you to these documents for further information concerning these matters.
Changes in ONEOK Ownership
On February 5, 2003, ONEOK repurchased from Westar Industries 9,038,755 shares of its Series A Convertible Preferred Stock, which were convertible into 18,077,511 shares of common stock. We received $300 million as a result of this sale, which was previously approved by the KCC. We anticipate using all or a portion of the net proceeds to repurchase or provide for the repayment of all of the putable/callable notes and a portion of our 6.875% senior unsecured notes.
Westar Industries also exchanged its remaining shares of Series A Convertible Preferred Stock for 21,815,386 new shares of ONEOK’s Series D Convertible Preferred Stock. ONEOK has agreed to file a shelf registration statement covering the Series D Convertible Preferred and common stock held by Westar Industries. Future sales will be subject to various conditions including the effectiveness of such registration, the required waiver or expiration of a 180-day lock-up period ending on July 22, 2003, and future market conditions. As of March 14, 2003, Westar Industries holds an approximate 27.5% ownership interest in ONEOK, assuming conversion of the Series D Convertible Preferred Stock.
In 2002 and prior periods, we accounted for our ONEOK common stock investment under the equity method of accounting. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and mark to market its fair value through other comprehensive income. We will begin accounting for our ONEOK Series D Convertible Preferred Stock investment under this method if and when a public market for these securities develops.
Sale of Protection One and Protection One Europe
On January 13, 2003, we announced that our board of directors authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe. The Debt Reduction Plan provides for the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. As a result, these operations were classified as discontinued operations during the first quarter of 2003 pursuant to the provisions of SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.”
As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount, which could be material, by which our basis exceeds the estimated fair value.
We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be
due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.
Ongoing Investigations
Grand Jury Subpoena
On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and the company in general. We are providing information in response to these requests and are fully cooperating in the investigation. We have not been informed that we are a target of the investigation. We are unable to predict the ultimate outcome of the investigation or its impact on us.
Securities and Exchange Commission Inquiry
On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these matters and other matters within the scope of the grand jury investigation. We are unable to predict the ultimate outcome of the inquiry or its impact on us.
Special Committee Investigation
Our board of directors appointed a Special Committee of directors to investigate management matters and matters that are the subject of the grand jury investigation and SEC inquiry. The Special Committee retained counsel and other advisors. The Special Committee investigation has been completed and has not resulted in adjustments to our consolidated financial statements.
FERC Subpoena
On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation (Cleco) and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries.
We have provided information to FERC in response to the subpoena. We believe that our participation in these transactions did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation. See Note 19 of the Notes to Consolidated Financial Statements, “Ongoing Investigations - FERC Subpoena,” for additional information.
Call Option
In August 1998, we entered into a call option with an investment bank related to the issuance of $400 million of our putable/callable notes. This call option is required to be settled by August 2003 through either a cash payment or a remarketing or refinancing of the putable/callable notes. The ultimate value of the call option will be based on the difference between the 10-year United States treasury rate on August 12, 2003 and 5.44%. If the 10-year United States treasury rate on August 12, 2003 is less than 5.44%, we will have a liability to the investment bank at that time. At December 31, 2002, our potential liability under the call option was $62.2 million. Based on the 10-year forward treasury rate on March 14, 2003 of 3.91%, we would be obligated to make a cash payment of approximately $69.1 million to settle the call option if we did not remarket or refinance the notes. The amount of our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. If settled through a remarketing or refinancing, any liability related to the call option will be amortized as a credit to interest expense over the term of the new debt. The investment bank will price the notes to yield a market premium adequate to allow the investment bank to retain proceeds equal to the fair value of the call option at settlement.
At the time of issuance of the notes in 1998, we were not required by generally accepted accounting principles (GAAP) to account separately for the call option. However, when we began retiring these notes as a part of our overall debt reduction strategy, the portion of the call option associated with the retired notes became a free-standing option required to be treated as a derivative instrument under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). In addition, under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our balance sheet reflects the current fair value of the free standing portion of the call option. For 2002, we recognized a loss of $10.1 million, net of $6.7 million tax benefit, related to the fair value of the call option associated with the putable/callable notes at the time the notes were retired. This loss is included in our consolidated statements of income as part of the gain on extinguishment of debt line item of other income. For 2002, we also recorded an additional non-cash charge of $13.6 million, net of $9.0 million tax benefit, to reflect mark to market changes in the fair value of the call option associated with the retired notes. This charge is reflected in the other line item of other income in our consolidated statements of income. In total, the loss recorded related to the fair value of the call option for the year ended December 31, 2002 was $23.7 million, net of $15.7 million tax benefit.
We intend to repurchase or provide for the repayment of the putable/callable notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. From January 1, 2003 through March 14, 2003, we purchased $35.3 million face value of our putable/callable notes. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.
Impairment Charges
Effective January 1, 2002, we adopted SFAS No. 142, “Accounting for Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” As a result of implementing the new standards, we recorded a charge for the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.
In addition, in the fourth quarter of 2002 we recorded a $79.7 million impairment charge, net of tax benefit and minority interests, to reflect the additional impairment of all remaining goodwill of Protection One’s North America segment. We also recorded a $36 million impairment charge to reflect the impairment of all remaining goodwill at Protection One Europe. These accounting standards, the related charges and other related information are discussed in Note 23 of the Notes to Consolidated Financial Statements, “Impairment Charges.”
Work Force Reductions
During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We recorded a net charge of approximately $21.7 million in 2002 related to this program. We have replaced and may continue to replace some of these employees. For additional information, see Note 29 of the Notes to Consolidated Financial Statements, “Work Force Reductions.”
Ice Storm
In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. Through December 31, 2002, we incurred $19.3 million for restoration costs, a portion of which was capitalized. We have deferred and recorded as a regulatory asset on our December 31, 2002 consolidated balance sheet restoration costs of approximately $15.0 million. We have received an accounting authority order from the KCC that allows us to accumulate and defer for potential future recovery all operating and carrying costs related to storm restoration.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, depreciation, revenue recognition, investments, customer accounts, goodwill, intangible assets, income taxes, pensions, post-retirement and post-employment benefits, decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” provides a summary of the significant accounting policies and methods used in the preparation of our consolidated financial statements. The following is a brief description of the more significant accounting policies and methods used by us.
Regulatory Accounting
We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with 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 obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. As of December 31, 2002, this would reduce our earnings by approximately $351.9 million, net of applicable income taxes.
SFAS No. 71 applies to our electric utility business segment. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See “- Other Information - Electric Utility - Stranded Costs” for additional discussion of the application of SFAS No. 71.
Depreciation
Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or 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 2.66% during 2002, 3.03% during 2001 and 2.99% during 2000.
In its rate order of July 25, 2001, the KCC extended the estimated service life for certain of our generating assets, including Wolf Creek and the LaCygne 2 generating station, for regulatory rate making purposes. The estimated retirement date for Wolf Creek was extended from 2025 to 2045, although our operating license for Wolf Creek expires in 2025, and the estimated retirement date for LaCygne 2 was extended to 2032, although the term of our lease for LaCygne 2 expires in 2016. On April 1, 2002, we adopted the new depreciation rates as prescribed in the KCC order. We continue to depreciate Wolf Creek over the term of our operating license, and we continue to depreciate LaCygne 2 over the term of our lease. We have created a regulatory asset for the amount that our depreciation expense exceeds our regulatory depreciation expense.
On an annual basis, our depreciation expense will be reduced by approximately $30.0 million as a result of these extensions. If our generating license for Wolf Creek is not renewed or the term of our lease for LaCygne 2 is not extended, we will need to seek relief from the KCC to recover the remaining cost of these assets.
Pension Benefit Plans
The reported costs of our pension benefit plans, which include our portion of Wolf Creek Nuclear Operating Corporation’s costs, are impacted by the factors listed below.
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Pension costs are impacted by earnings on plan assets, plan amendments, contributions made to the plan and employee demographics (including age, compensation levels and employment periods).
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Pension costs may be significantly affected by changes in actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the projected benefit obligation and pension costs.
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Our 2002 discount rate assumption ranged from 6.50% to 6.75%. Our discount rate was 7.25% in 2001 and ranged from 7.25% to 7.75% in 2000. When our discount rate assumption decreases, our expense increases.
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Our expected rate of return assumption ranged from 9.0% to 9.25%, which is consistent with long-term results of the plans. The return assumption was the same for 2002, 2001 and 2000.
The following chart reflects the annual impact of a 0.5 % decrease in certain assumptions. If the discount rate increased by 0.5%, the impact would be a similar amount in the opposite direction.
We recorded pension expense of $5.8 million in 2002 and pension income of $4.0 million in 2001. The $9.8 million increase is due primarily to lower returns on plan assets and an early retirement window that was offered in 2001 and 2002. In 2003 we expect to record approximately $1.8 million of pension income.
Pension plan assets are primarily made up of equity and fixed income investments. The market value of the plan assets has been affected by declines in equity markets. At December 31, 2002, the fair value of pension plan assets was $382.3 million. Actual return on plan assets declined by approximately $2.1 million during 2001 and by approximately $58.5 million during 2002. Absent a substantial recovery in the equity markets, pension costs, cash funding requirements and the additional pension liability could substantially increase in future years.
See Note 15 of the Notes to Consolidated Financials Statements, “Employee Benefit Plans,” for additional information.
Revenue Recognition
Energy Sales
Energy sales are recognized as delivered and include an estimate for energy delivered but unbilled at the end of each year. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets.
We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results.
Monitored Services Revenues
Monitored services revenues are recognized when security services are provided. System installation revenues, sales revenues on equipment upgrades and direct and incremental costs of installations and sales are deferred for residential customers with monitoring service contracts. For commercial customers, revenue recognition is dependent upon each specific customer contract. In instances when the company passes title to a system unaccompanied by a service agreement or the company passes title at a price that it believes is unaffected by an accompanying but undelivered service, the company recognizes revenues and costs in the period incurred. In cases where the company retains title to the system or it prices the system lower than it otherwise would because of an accompanying service agreement, the company defers and amortizes revenues and direct costs.
Deferred system and upgrade installation revenues are recognized over the expected life of the customer utilizing an accelerated method for residential and commercial customers and a straight-line method for Protection One’s Multifamily customers. Deferred costs in excess of deferred revenue are recognized over the initial contract term, utilizing a straight-line method, typically two to three years for residential systems, five years for commercial systems and five to ten years for Multifamily systems. To the extent deferred costs are less than deferred revenues, such costs are recognized over the estimated life of the customer relationship.
Deferred revenues also result from customers who are billed for monitoring and extended service protection in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. Revenues from monitoring activities are recognized in the period such services are provided.
Cumulative Effects of Accounting Changes
Accounting for Goodwill and for the Impairment and Disposal of Long-Lived Assets
Effective January 1, 2002, we adopted SFAS No. 142 and SFAS No. 144. SFAS No. 142 established new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinued amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards.
SFAS No. 144 established a new approach to determining whether our customer account asset is impaired. The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of the reporting unit, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then we are required to mark the customer account asset down to fair value, by way of recording an impairment, to the extent fair value is less than our book value. To the extent net book value is less than fair value, no impairment would be recorded.
To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, we recorded a charge in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.6 million was related to goodwill and $193.9 million was related to customer accounts.
Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001, we adopted SFAS No. 133. We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in some of our fossil fuel and electricity purchases and sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value. Changes in a derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met, in which case changes are reflected in other comprehensive income. Cash flows from derivative instruments are presented in net cash flows from operating activities.
Derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales are classified as energy trading contracts on our consolidated balance sheets. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income in 2001 as a cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under “- Revenue Recognition - Energy Sales.” Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings.
Revenue Recognition
In the fourth quarter of 2000, we adopted Staff Accounting Bulletin (SAB) No. 101, “Revenue Recognition,” which had a retroactive effective date of January 1, 2000. The impact of this accounting change generally required deferral of certain monitored security services sales for installation revenues and direct sales-related expenses. Deferral of these revenues and costs is generally necessary when installation revenues have been received and a monitoring contract to provide future service is obtained.
The cumulative effect of this change in accounting principle was a charge to income in 2000 of approximately $3.8 million, net of $1.1 million tax benefit, and is related to changes in revenue recognition at Protection One Europe. Prior to the adoption of SAB No. 101, Protection One Europe recognized installation revenues and related expenses upon completion of the installation.
Accounting Changes
Accounting for Energy Trading Contracts
In October 2002, the Financial Accounting Standards Board (FASB), through the Emerging Issues Task Force (EITF), issued Issue No. 02-03, which rescinded Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, all new contracts that would otherwise have been accounted for under Issue No. 98-10 and that do not fall within the scope of SFAS No. 133 can no longer be marked-to-market and recorded in earnings as of October 25, 2002. We are not affected by this change in accounting principle and are not required to reclassify any of our contracts. EITF Issue No. 02-03 also requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. We began to classify our energy trading contracts on a net basis during the third quarter of 2002.
On July 1, 2002, we began reporting mark-to-market gains and losses on energy trading contracts on a net basis, whether realized or unrealized, in our consolidated income statements. Prior to July 1, 2002, we reported gains on these contracts in sales and losses in cost of sales in our consolidated income statements. The changes are reflected in our consolidated financial statements for the year ended December 31, 2002. Prior periods shown in our consolidated financial statements have been reclassified to reflect the effect of this change and to be comparable as required by GAAP. As a result of the net presentation, we expect significant reductions in our energy revenues and expenses from those reported in prior periods, which will not affect gross profit or net income. A summary of the effects of this change for the years ended December 31, 2002, 2001 and 2000 is as follows:
Changes to Income Statements
OPERATING RESULTS
Westar Energy Consolidated
2002 compared to 2001
We reported a loss of $11.06 per share in 2002 compared to a loss of $0.31 per share in 2001. This greater loss per share was due primarily to the 2002 impairment charges related to monitored services goodwill and customer accounts. A decline in monitored services revenues also contributed to the loss. Improved results from utility operations and declines in cost of sales and operating expenses and increases in other income from monitored services partially offset these items. For additional information, see the segment discussions below.
2001 compared to 2000
We reported a loss of $0.31 per share in 2001 compared to earnings of $1.96 per share in 2000. This decrease resulted from decreased electricity sales caused by milder weather, the decrease in electric rates in accordance with the July 25, 2001 KCC rate order, higher operating losses in our monitored services segment, and the fourth quarter charge related to a work force reduction. Additionally, investment earnings and extraordinary gains on the retirement of debt were lower in 2001 than in 2000.
Segments of Business
Our business is segmented based on differences in products and services, production processes and management responsibility. We have identified three reportable segments: Electric Utility, Monitored Services and Other.
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Electric Utility consists of our integrated electric utility operations, including the generation, transmission and distribution of power to our retail customers in Kansas and to wholesale customers, and our power marketing activities.
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Monitored Services, including the net effect of minority interests, is comprosed of our security alarm monitoring businesses in the United States and Europe.
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Other includes our approximate 45% ownership interest in ONEOK at December 31, 2002, (which was reduced to a 27.5% interest on February 5, 2003) and other investments in the aggregate not material to our business or results of operations.
We manage our business segments’ performance based on their earnings (losses) before interest and taxes (EBIT) because EBIT is the primary measurement used by our management to evaluate segment performance. Our business managers have direct control over the items that affect the EBIT of their segments and we therefore believe EBIT is an appropriate measure of segment performance. EBIT does not represent cash flow from operations as defined by GAAP, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund our cash needs. Items excluded from EBIT are significant components in understanding and assessing our financial performance. Interest expense, income taxes, discontinued operations, cumulative effects of accounting changes and preferred dividends are items that are excluded from the calculation of EBIT. Our computation of EBIT may not be comparable to other similarly titled measures of other
companies. We provide a reconciliation of EBIT to GAAP income measurements in Note 32 of the Notes to Consolidated Financial Statements, “Segments of Business.”
Electric Utility
We supply electric energy at retail to approximately 647,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We classify our customers as residential, commercial and industrial as defined in our tariffs. We also supply electric energy at wholesale to the electric distribution systems of 62 Kansas cities and four rural electric cooperatives. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we have power marketing operations that purchase and sell electricity in areas outside our historical service territory.
Regulated electric utility sales are significantly impacted by such things as regulation (including 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 demand outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity.
Our electric sales for the three years ended December 31 were as follows:
The following tables show changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity we generate, for the three years ended December 31. No sales volumes are shown for network integration or power marketing because these activities are not related to electricity we generate.
Details concerning EBIT and assets attributable to our electric utility segment are summarized in the tables below:
compared to 2001: Energy sales increased $115.7 million, or 9%, due primarily to the $60.1 million in new network integration tariff revenues (see “- Other Information - Electric Utility - Network Integration Transmission Service”), a $33.4 million increase in power marketing, wholesale and interchange revenues and a $27.7 million increase in residential and commercial electric sales revenues. Power marketing, wholesale and interchange revenues increased primarily as a result of increased sales volumes, offset by lower wholesale prices. Favorable weather conditions and a slight increase in the number of utility customers contributed to the increase in residential and commercial electric sales revenues, which were offset by lower retail rates and decreased industrial revenues related to weak economic conditions.
Cost of sales decreased $15.4 million, or 4%, due primarily to a $14.6 million decrease in purchased power expense. Purchased power expense decreased due primarily to the increased availability of our generating units and lower prices.
Gross profit increased $131.2 million, or 14%, for the reasons discussed above. This increase in gross profit also reflects the impact of the adoption of SFAS No. 133 on January 1, 2001. This new standard required that we report a $31.0 million gain in 2001 on certain derivative contracts (derivatives) as a cumulative effect of a change in accounting principle rather than include the gain in gross profit. All gains and losses after January 1, 2001 on our derivatives that are not designated as hedges are reflected in gross profit. Had we included the $31.0 million gain in revenues in 2001, gross profit would have increased $100.1 million rather than $131.2 million.
Operating expenses increased $69.0 million, or 10%, due primarily to the charges associated with the network integration transmission tariff, reserve for potential liabilities to Mr. Wittig and Mr. Lake, employee severance costs related to the work force reduction and the compensation expense associated with an exchange of previously granted restricted share units as discussed in Note 15 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans - Stock Based Compensation Plans.” These increases were partially offset by a $13.4 million decrease in depreciation expense related to the change in depreciation rates as discussed above in “- Critical Accounting Policies - Depreciation.” In addition, our maintenance expense declined $22.6 million, or 19%, due primarily to the lower forced outage rates of our generating units.
Due to the above factors, income from utility operations increased $62.2 million, or 29%. A decrease in other expense of $22.3 million was due primarily to recording a non-cash mark-to-market charge on the call option of the putable/callable notes as discussed in “- Liquidity and Capital Resources” below. EBIT increased $39.9 million as a result.
compared to 2000: Energy sales decreased $52.3 million, or 4%. Residential sales declined 7% and power marketing, wholesale and interchange sales declined 11%. Residential sales decreased due to weather conditions and our rate decrease, while power marketing, wholesale and interchange sales decreased because of lower prices and more power available in the market. Cost of sales increased $13.7 million, or 4%, which was due principally to an increase in our natural gas fuel expenses resulting from the purchase of fuel for new generating units that began operating during 2001.
As a result of the decline in sales and the increase in cost of sales, gross profit decreased $66.0 million, or 7%. This decline in gross profit also reflects the impact of the adoption of SFAS No. 133 on January 1, 2001. This new standard required that we report a $31.0 million gain on certain derivatives as a cumulative effect of a change in accounting principle rather than include the gain in gross profit. Had we been permitted to classify this accounting change as an increase to revenues, gross profit would have declined by $35.0 million rather than $66.0 million.
Operating expenses increased $45.7 million due primarily to recording approximately $8.7 million of costs associated with the terminated Public Service Company of New Mexico merger transaction, approximately $14.3 million in employee-severance costs related to the 2001 work force reductions, an increase in our pension and benefit expenses and an increase in general maintenance expenses.
Monitored Services
Protection One and Protection One Europe comprise our monitored services business segment. The results discussed below reflect monitored services on a stand-alone basis. These results take into consideration Protection One’s minority interest of approximately 12% at December 31, 2002, 13% at December 31, 2001, and 15% at December 31, 2000. As discussed above, our monitored services operations will be reported as discontinued operations as required by of SFAS No. 144 during the first quarter of 2003.
Details concerning EBIT and assets attributable to our monitored services segment are as follows:
compared to 2001: Sales decreased $60.4 million due primarily to a decline in the average customer base and the renewal of existing customers for extended contract periods with a lower monthly rate. The monitored services segment experienced a net decline of 62,656 customers in 2002, which is attributable primarily to customer attrition. Although net customers decreased for the year, Protection One had a favorable decline in attrition in 2002 compared to 2001 due to the reasons discussed in “- Other Information - Monitored Services - Attrition” below.
Protection One expects that the decline in its customer base will continue until the efforts it is making to generate new accounts and reduce attrition become more successful than they have been to date. Until it is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. For 2003, Protection One’s focus is on improving returns on invested capital by realizing economies of scale from increasing customer density in the largest urban markets in the United States. It plans to accomplish this by improving customer retention. See “- Other Information - Monitored Services - Attrition” below for additional information.
Cost of sales decreased $11.9 million due primarily to a reduction of telecommunication costs and consolidation of Protection One’s monitoring functions. Operating expenses increased $310.4 million due primarily to the 2002 impairment charges. Partially offsetting the increase in operating expenses was a decline in depreciation and amortization expense, which reflects a reduction in customer account amortization related to the impairment charges and elimination of goodwill amortization due to the implementation of SFAS No. 142. Also partially offsetting the increase in operating expenses were reductions in professional fees and outside services because of the completion of system integration projects and lower legal costs, a decrease in wage expense because of consolidation efforts, and a decline in bad debt expense and collection costs.
As a result of the decline in gross profit and the increase in operating expenses, loss before interest and taxes increased $292.8 million. Monitored services’ total assets decreased approximately $1.2 billion primarily as a result of the impairment of goodwill and customer account assets.
2001 compared to 2000: Sales decreased $121.3 million due primarily to a decline in the monitored services segment’s average customer base and the disposition of certain operations. The monitored services segment experienced a net decline of 272,549 customers in 2001. This decrease in customers is attributable primarily to customer attrition and a decrease of 63,875 customers due to the disposition of operations. Additionally, the number of Protection One customers declined by 62,443 customers due to the conversion of accounts to a common billing and monitoring system. This new system reports number of customer accounts on the basis of one customer for every location provided service even if Protection One has separate contracts to provide multiple services at a given location. Previous systems utilized a number of different billing and monitoring software programs, some of which would count each separate contracted service as a separate account regardless of location.
Loss before interest and taxes increased $71.4 million due primarily to the decrease in sales. Cost of sales decreased $41.7 million due primarily to the discontinuation of Protection One’s patrol services in May 2001, consolidation of Protection One customer monitoring facilities, a reduction of Protection One’s telecommunications expense, consolidation of monitoring and customer service functions and the decline in customer accounts caused by dispositions of operations and attrition. See “- Other Information - Monitored Services - Attrition” below for additional information.
Other
Other includes an approximate 45% interest in ONEOK at December 31, 2002, and other investments in the aggregate not material to our business or results of operations. Details concerning EBIT attributable to this segment are as follows:
compared to 2001: Sales shown above are from a paging services business that was sold in the first quarter of 2002. EBIT increased approximately $44.6 million primarily as a result of greater investment earnings, which increased $32.8 million as a result of the receipt of a one-time payment of approximately $14.2 million related to a partial recovery of an investment and the $11.1 million write down in 2001 of the cost basis to the fair value of certain securities held for investment. We also had a $16.3 million decline on the loss on the extinguishment of debt.
compared to 2000: EBIT decreased approximately $145.3 million due to various events affecting investment earnings in 2001 and 2000. Investment earnings in 2001 included $41.8 million of ONEOK investment income and a $5.3 million gain related to the sale of an investment. These earnings were reduced by an $11.1 million write down in 2001 of the cost basis to the fair value of certain securities held for investment and other investments. Investment earnings in 2000 included $45.3 million of ONEOK investment income, a $91.1 million gain from the sale of our investment in a gas compression company, a $9.6 million gain related to an investment and a $24.9 million gain from the sale of investments in paging companies.
WESTAR ENERGY CONSOLIDATED
The following discussion addresses changes in other items affecting net income for the years ended December 31, 2002, 2001 and 2000.
Interest Expense
compared to 2001
Interest expense increased $8.5 million due primarily to higher interest rates. In 2002, we refinanced short-term debt with long-term debt issued at interest rates higher than the interest rate on the short-term debt. The weighted average interest rate on debt outstanding increased to 6.34% at December 31, 2002 from 3.43% at December 31, 2001.
2001 compared to 2000
Interest expense decreased $20.7 million due to lower interest rates and lower outstanding debt at Protection One. The weighted average interest rate on our $500 million revolving credit facility that was retired with proceeds from the May 10, 2002 and June 6, 2002 debt refinancings declined to 3.43% at December 31, 2001 from 8.11% at December 31, 2000.
Income Taxes
2002 compared to 2001
Income taxes decreased $89.3 million in 2002 compared to 2001. This was due primarily to the increased loss before income taxes and flow through tax benefits associated with our security business. Our overall effective tax rate changed from a 64.0% benefit in 2001 to a 48.7% benefit in 2002. The change in our effective tax rate was due primarily to decreased earnings before income taxes and flow through tax benefits associated with our security business, including minority interest share of tax benefits and goodwill impairment. Other flow through tax benefits from dividends received, low income housing tax credits, the amortization of prior years’ investment tax credits, tax reserve adjustment and the tax benefits from corporate owned life insurance contributed to this change in the effective tax rate.
2001 compared to 2000
Income taxes decreased $140.7 million in 2001 compared to 2000. This was due primarily to having a loss before income taxes in 2001. Our overall effective tax rate changed from a 33.9% expense in 2000 to a 64.0% benefit in 2001. The change in our effective tax rate was due primarily to having a loss before income taxes in 2001. The tax benefit from having a loss, combined with flow through net tax benefits from dividends received, low income housing tax credits, the amortization of prior years’ investment tax credits, the amortization of non-deductible goodwill, the effect of state income taxes and the tax benefits from corporate owned life insurance created this swing in the effective tax rate.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We believe we will have sufficient cash to fund future operations of our business, debt reductions, including the annual $100 million debt reductions in 2003 and 2004 ordered by the KCC, and the payment of dividends, from a combination of cash on hand, cash flow, proceeds from the sales of our non-utility and non-core assets and available borrowings under our revolving credit facility. Uncertainties affecting our ability to meet these requirements include, among others, the factors affecting sales described above, economic conditions, including the impact of inflation on operating expenses, regulatory actions, including the KCC orders received in the last quarter of 2002 and first quarter of 2003, our ability to implement the Debt Reduction Plan, compliance with future environmental regulations and the impact of our monitored services’ operations and financial condition.
As of December 31, 2002, our total outstanding long-term debt was approximately $3.4 billion, of which approximately $3.0 billion was the obligation of our utility operations. In addition, as of December 31, 2002, our long-term liabilities included $214.5 million related to outstanding mandatorily redeemable preferred securities. This large amount of indebtedness could have a negative impact on, among other things, our ability to obtain additional financing in the future for working capital, capital expenditures and general corporate purposes and our ability to withstand a downturn in our business or the economy in general.
At December 31, 2002, current maturities of long-term debt increased $148.8 million from 2001 due primarily to the upcoming maturities of the Kansas Gas and Electric Company (KGE) 7.6% first mortgage bonds that are due December 15, 2003 and the putable/callable notes due on August 15, 2003. We have irrevocably deposited with the bond trustee funds sufficient to provide for the future principal and interest payments on these 7.6% first mortgage bonds.
Capital Resources
We had $123 million in cash and cash equivalents at December 31, 2002. We consider cash equivalents to be highly liquid investments with a maturity of three months or less when purchased. At December 31, 2002, we also had $159 million of restricted cash classified as a current asset and $35.8 million of restricted cash classified as a long-term asset. The following table details our restricted cash as of December 31, 2002:
We had $149 million of available borrowings under our revolving credit facility at December 31, 2002.
The Debt Reduction Plan provides for a systematic disposal of our non-utility and non-core assets and, if necessary, a sale of our equity. The proceeds of these transactions will be used to reduce debt. We may reduce debt pursuant to terms stated in the debt agreements or through open market purchases or tender offers. We may engage a financial advisor to assist in completing debt repurchases in the most cost-effective manner.
We have registered debt securities for sale with the SEC. As of December 31, 2002, these included $400 million of unsecured senior notes, $500 million of our first mortgage bonds, and $50 million of KGE first mortgage bonds. Any issuance of debt would require that we seek KCC approval.
The Westar Energy mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless Westar Energy’s unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on, and 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2002, $70.4 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with refundings.
KGE’s mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless KGE’s net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2002, approximately $302.5 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
We may from time to time issue equity securities in private transactions and public offerings. We have approximately 11.2 million shares of common stock registered for sale with the SEC.
Cash Flows from (used in) Operating Activities
Our primary sources of operating cash flows are the operations of our electric utility and monitored services businesses and dividends from our ONEOK investment. Cash flows from operating activities increased $154.4 million to $372.7 million in 2002, from $218.3 million in 2001. This increase is mostly attributable to an approximate $131.2 million increase in utility gross margin for 2002 compared to 2001.
Cash flows from operating activities decreased $252.2 million to $218.3 million in 2001, from $470.8 million in 2000. This decrease is mostly attributable to changes in our working capital. Operating cash flows in 2001 also decreased due to the continued declines in Protection One’s and Protection One Europe’s customer bases, which reduced our recurring monthly cash flow stream. Operating cash flows also decreased in 2001 as we purchased additional coal to restock our inventory from the levels that existed in December 2000.
Cash Flows from (used in) Investing Activities
In general, cash used for investing purposes relates to the growth and maintenance of the operations of our electric utility and monitored services businesses. The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $126.8 million in 2002, $227.0 million in 2001 and $285.4 million in 2000 on net additions to utility property, plant and equipment, which included $52.2 million in 2001 and $87.7 million in 2000 for new generation facilities. We did not construct any new generation facilities in 2002. The monitored services business also requires significant capital related to the generation of customer accounts. Investment in customer accounts amounted to $43.4 million in 2002, $23.1 million in 2001 and $45.7 million in 2000.
Investing cash flows were also impacted significantly by dispositions of monitored services businesses and the sale of marketable securities. These activities provided cash of $16.8 million in 2002, $50.8 million in 2001 and $218.6 million in 2000.
Cash Flows from (used in) Financing Activities
We used $203.6 million of net cash flows in 2002 for financing activities compared to net cash flows from financing activities of $22 million in 2001, primarily due to the debt refinancings completed during 2002. In 2001, an increase in short-term debt was the principal source of cash flows from financing activities. Cash from financing activities was used to fund the retirement of long-term debt, deposits to the trustee to provide for repayment of an obligation, the acquisition of treasury stock, and the payment of dividends on our common stock. In 2000, we reduced our indicated annual dividend from $2.14 per share to $1.20 per share. This reduction, and
continued reinvestment of dividends by our shareholders through the dividend reinvestment program, resulted in a significant reduction in our net cash dividend requirements.
Future Cash Requirements
The November 8, 2002 KCC order requires us to reduce debt by $100 million annually in each of the next two years from internally generated cash flow. While we believe we can generate this level of internally generated cash flow, if we fail to meet this requirement, the KCC may, among other things, require us to reduce or eliminate our dividend or issue equity securities. In the Debt Reduction Plan, we anticipate meeting the $100 million debt reduction goal.
We have a potential obligation to make a cash payment related to the call option associated with our putable/callable notes. See “- Summary of Significant Items - Call Option” above for additional information.
Our business requires significant capital investments. Through 2005, we expect we will need cash mostly for ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. We do not anticipate needing additional generating capacity through 2005.
Capital expenditures for 2002 and anticipated capital expenditures for 2003 through 2005 are as follows:
These estimates are prepared for planning purposes and will be revised from time to time as discussed in Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies.” Actual expenditures will differ from our estimates.
Maturities of long-term debt as of December 31, 2002 are as follows:
Contractual Obligations and Commercial Commitments
In the course of our business activities, we enter into a variety of contractual obligations and commercial commitments. Some of these result in direct obligations that are reflected in our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, that are 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 as of December 31, 2002, and represent only amounts that we were contractually obligated to meet as of December 31, 2002.
Contractual Cash Obligations
The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2002:
(a)
See Note 12 of the Notes to Consolidated Financial Statements, “Long-Term Debt,” for individual long-term debt maturities.
(b)
See “- Future Cash Requirements” above for a description of funds that have been irrevocably deposited with the bond trustee for repayment of debt.
(c)
We have an obligation to reduce debt by $100 million annually in 2003 and 2004.
Long-term debt: Our long-term debt existing as of December 31, 2002 is debt that has a final maturity of January 1, 2003 or later (including current maturities of long-term debt). See Note 12 of the Notes to Consolidated Financial Statements, “Long-Term Debt,” for detailed information.
Capital leases: We maintain capital leases in the ordinary course of our business activities. These leases primarily include those for vehicles and equipment. See Note 25 of the Notes to Consolidated Financial Statements, “Leases,” for additional information.
Operating leases: We maintain operating leases in the ordinary course of our business activities. These leases include those for office space, operating facilities, office equipment and operating equipment. These leases have various terms and expiration dates from 1 to 16 years. See Note 25 of the Notes to Consolidated Financial Statements, “Leases,” for additional information.
Fossil fuel: To supply a portion of the fossil fuel requirements for our generating plants, we have entered into various commitments to obtain and deliver coal and for natural gas transportation. Some of these contracts contain provisions for price escalation and minimum purchase commitments. For additional information, see Note 17 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies - Fuel Commitments.”
Nuclear fuel: To supply a portion of the fuel requirements for Wolf Creek, we have entered into various commitments to obtain nuclear fuel consisting of uranium concentrates, conversion and enrichment. See Note 17 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies - Fuel Commitments,” for more details.
Call option on putable/callable notes: For information concerning a potential liability under the call option related to the issuance of $400 million of our putable/callable notes, see Note 14 of the Notes to Consolidated Financial Statements, “Call Option.”
Unconditional purchase obligations: We use purchase obligations as part of our ongoing utility operations and construction program. Protection One’s unconditional purchase obligations represent its contract tariff for telecommunication services. See Note 17 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies - Purchase Orders and Contracts,” for additional information.
Commercial Commitments
The following table summarizes our commercial commitments by date of expiration existing at December 31, 2002:
Lines of credit: Certain banks provide us a revolving credit facility on a committed basis totaling $150 million. As of December 31, 2002, borrowings on the revolving credit facility were $1.0 million, leaving $149 million remaining under this facility. In addition, we have a commitment to Protection One for a line of credit of up to $228.4 million. As of March 14, 2003, Protection One had borrowed $215.5 million under this facility, resulting in an undrawn commitment of $12.9 million. This commitment is eliminated in consolidation and is therefore not included in the table above.
Outstanding letters of credit: We obtain letters of credit in the ordinary course of our operating activities for energy trading, worker’s compensation, an aircraft lease and surety bonds. As of December 31, 2002, we had outstanding letters of credit of $1.2 million related to our power marketing and trading activities and $8.7 million related to other operating activities.
Guarantees: In 1998, we issued a financial guarantee of an obligation of Onsite Energy Corporation under which our maximum liability was $1.3 million. This guarantee was released in the first quarter of 2003.
Debt Covenants
Our debt financing agreements require, among other restrictions, that we satisfy certain financial covenants. These debt instruments contain restrictions based on EBITDA. The definition of EBITDA varies among the various indentures. EBITDA is generally derived by adding to income (loss) before income taxes, the sum of interest expense and depreciation and amortization expense. However, under the varying definitions of the indentures, additional adjustments are required. A violation of these restrictions would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable. We are in compliance with these covenants. The most restrictive of these covenants in Westar Energy’s debt instruments are as follows:
•
Consolidated Leverage Ratio: Consolidated total debt to earnings before interest, taxes, depreciation and amortization (EBITDA) for the most recent four consecutive quarters must be less than 6.00 to 1.00 at December 31, 2002 and 5.75 to 1.00 each quarter thereafter until June 2005. At December 31, 2002, our ratio was 5.13.
•
Consolidated Interest Coverage Ratio: EBITDA to consolidated interest expense for the most recent four consecutive quarters must be greater than 2.00 to 1.00. At December 31, 2002, our ratio was 2.54.
•
Consolidated Debt to Total Capital Ratio: Consolidated total debt to consolidated total capital for the most recent quarter must be less than 0.65 to 1.00. At December 31, 2002, our ratio was 0.618.
The indentures governing Protection One’s public indebtedness require it to satisfy certain financial covenants in order to borrow additional funds. At December 31, 2002, Protection One was in compliance with the covenants under its debt instruments. The most restrictive of these covenants in Protection One’s debt instruments are as follows:
•
Total Debt to EBITDA Ratio: Total debt to annualized EBITDA for the most recent quarter must be less than 6.0 to 1.0. For the quarter ended December 31, 2002, the ratio was 4.0 to 1.0.
•
EBITDA to Interest Expense Ratio: EBITDA to interest expense for the most recent quarter must be greater than 2.25 to 1.0. For the quarter ended December 31, 2002, the ratio was 3.1 to 1.0.
•
Senior Debt to EBITDA Ratio: Senior debt to annualized EBITDA for the most recent quarter must be less than 4.0 to 1.0. For the quarter ended December 31, 2002, the ratio was 2.9 to 1.0.
The indentures contain other covenants that impose operational restrictions on Protection One that are not as burdensome to Protection One as those listed above, and none are based on credit ratings. A violation of the indenture covenants would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable.
Following a change of control of Protection One, its revolving credit facility provided by Westar Industries becomes due in full. The holders of Protection One’s senior subordinated discount notes and convertible notes have an optional redemption at approximately 101% of par, and holders of Protection One’s senior notes and senior subordinated notes have an optional redemption at 101% of par if a change in control is coupled with two ratings downgrades.
Sale of Accounts Receivable
On July 28, 2000, Westar Energy and KGE entered into an agreement under which we transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The agreement was amended on July 25, 2002 and is annually renewable upon agreement by all parties. The amendment to the agreement extended the term until July 23, 2003 and limited the amount of the accounts receivable we had a right to sell during certain periods to $125 million.
Under the terms of the agreement, Westar Energy and KGE may transfer accounts receivable to the bankruptcy-remote SPE, and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE’s receivables, including delinquency rates and debtor concentrations.
Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit, resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the conduit, which was $2.9 million for the year ended 2002, $5.4 million for the year ended 2001 and $3.7 million for the year ended 2000. These expenses are included in other income (expense) in our consolidated statements of income.
The outstanding balance of SPE receivables was $48.2 million at December 31, 2002 and $43.3 million at December 31, 2001, which is net of an undivided interest of $110.0 million and $100.0 million, respectively, in receivables sold by the SPE to the conduit. Our retained interest in the SPE’s receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit’s ownership interest in the SPE’s receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit and to absorb all credit losses incurred on any of the SPE’s receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets.
A termination event will be triggered under the terms of the agreement if Westar Energy’s credit rating ceases to be at least BB- by Standard & Poor’s Ratings Group (S&P) or if the issuer credit rating for Westar Energy ceases to be at least Ba3 by Moody’s Investors Service (Moody’s). If a termination event were to occur, the administrative agent would be required to give notice to us at least five business days prior to a termination of the facility. This notice provision allows for the administrative agent to waive the termination event by not giving notice or, in the event notice is given, allows us to repay the facility.
Refinancings
On May 10, 2002, we completed offerings for $365 million of our first mortgage bonds and $400 million of our unsecured senior notes, both of which will be due on May 1, 2007. The first mortgage bonds bear interest at an annual rate of 7 7/8% and the unsecured senior notes bear interest at an annual rate of 9 3/4%. Interest on the first mortgage bonds and unsecured senior notes is payable semi-annually on May 1 and November 1 of each year. The net proceeds from these offerings were used to repay outstanding indebtedness of $547 million under our existing secured bank term loan, provide for the repayment of $100 million of our 7.25% first mortgage bonds due August 15, 2002 together with accrued interest, reduce the outstanding balance on our existing secured revolving credit facility and pay fees and expenses of the transactions. In conjunction with our May 10, 2002 financing, we amended our secured revolving credit facility to reduce the total commitment under the facility to $400 million from $500 million and to release $100 million of our first mortgage bonds from collateral.
On June 6, 2002, we entered into a secured credit agreement providing for a $585 million term loan and a $150 million revolving credit facility, each maturing on June 6, 2005, provided that if we have not refinanced or provided for the payment of our putable/callable notes due August 15, 2003, or our 6.875% senior unsecured notes due August 1, 2004, at least 60 days prior to either of the respective due dates, the maturity date is the date 60 days prior to either of the respective due dates. All loans under the credit agreement are secured by KGE’s first mortgage bonds. The proceeds of the term loan were used to retire an existing $400 million revolving credit facility with an outstanding principal balance of $380 million, to provide for the repayment at maturity of $135 million principal amount of KGE first mortgage bonds due December 15, 2003 together with accrued interest, to repurchase approximately $45 million of our outstanding unsecured notes and to pay customary fees and expenses of the transactions.
Interest Rate Swap
Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on the term loan at 6.18%. In June 2002, we refinanced the term loan associated with this swap, which increased the effective rate of the swap to 6.43%. At December 31, 2002, the variable rate in effect for the term loan was 4.40%. Changes in the fair value of this cash flow hedge are due to fluctuations in the variable interest rate.
Capital Structure
Our consolidated capital structure at December 31, 2002 and 2001 was as follows:
Dividend Policy
Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining dividend policy are earnings, cash flows, capitalization ratios, regulation, including the KCC’s order requiring us to reduce our outstanding debt, competition and financial loan covenants. In
February 2003, we declared a first-quarter 2003 dividend of $0.19 per share. Our Articles of Incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. See Note 20 of the Notes to Consolidated Financial Statements, “Common Stock, Preferred Stock and Other Mandatorily Redeemable Securities,” for a description of these provisions. We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate.
Debt Repurchase Plans
Protection One may, from time to time, purchase its debt and equity securities in the open market or through negotiated transactions. We may also purchase our debt. The timing, terms of such purchases and amount of debt actually purchased will be determined based on KCC orders, market conditions and other factors.
Equity Issuance Plans
We may, from time to time, issue equity securities.
Credit Ratings
S&P, Moody’s and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal on our securities.
On April 2, 2002, Moody’s downgraded its ratings on Protection One’s outstanding securities with the outlook remaining negative. On April 29, 2002, Moody’s confirmed our ratings with a negative outlook. On January 29, 2003, Fitch revised our and KGE’s Rating Watch status from evolving to negative, but on March 11, 2003, Fitch affirmed its ratings for us and KGE and removed the ratings from Rating Watch Negative. Following the filing of the Debt Reduction Plan with the KCC, S&P affirmed its ratings for us and KGE and removed all ratings from CreditWatch Negative, changing such designation to CreditWatch Developing on February 6, 2003.
As of March 14, 2003, ratings with these agencies are as follows:
In general, declines in our credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us. Westar Energy and KGE do not have any credit rating conditions in any of the agreements under which our debt has been issued, except for conditions in the agreements governing the sale of our accounts receivable discussed above.
OTHER INFORMATION
Electric Utility
Potential Sale of Utility Assets
On October 14, 2002, we announced an agreement with Midwest Energy, Inc. (Midwest Energy) for the sale to Midwest Energy of a portion of our transmission and distribution assets and rights to provide service to customers in an area of central Kansas. The sale will affect about 10,000 customers, or about 1.5% of our total customers, over 895 square miles. The area, which includes 42 towns, is on the west edge of our service territory and is largely surrounded by Midwest Energy’s existing territory. The proposed sale is contingent upon approval by
the KCC and FERC. KCC hearings have been scheduled to begin on May 20, 2003. We can give no assurance as to when or if this transaction will occur. From time to time we may consider similar transactions.
City of Wichita Franchise
KGE’s franchise with the City of Wichita to provide retail electric service is effective through December 1, 2003. We are currently negotiating with the City of Wichita for a long-term franchise agreement. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise. Customers within the Wichita metropolitan area account for approximately 21% of our total energy sales volumes.
Network Integration Transmission Service
Effective January 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. This provides a cost-effective way for us to participate in a broader market of generation resources with the possibility of lower transmission costs. This tariff provides for a zonal rate structure, whereby transmission customers pay a pro rata share, in the form of a reservation charge, for the use of the facilities for each transmission owner that serves them. As a result, the SPP has operational control over our transmission system, although we still own our transmission assets and maintain responsibility for dispatching, maintenance and storm restoration.
Currently, all revenues collected within a zone are allocated back to the transmission owner serving the zone. Since we are a transmission provider for our zone and are currently the only transmission customer taking service from that zone, we are currently being assessed 100% of the zonal costs and receiving all of the costs back as revenue, less servicing fees. In 2002, these network integration transmission costs were approximately $65.9 million, and the associated revenues were approximately $60.1 million, for a net expense of approximately $5.8 million. The revenues received are reflected in electric operating revenues, and the related charges are expensed.
Stranded Costs
Stranded costs for a utility business are commitments or investments in, and carrying costs on, property, plant and equipment, and other regulatory assets that exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our electric utility operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings. Reasons for discontinuing SFAS No. 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred or a significant change by regulators from a cost-based rate regulation to another form of rate regulation. We periodically review SFAS No. 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based upon competitive or other events, such as successful municipalization by areas we serve, the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek, may be significantly impacted.
Regulatory changes could adversely impact our ability to recover our investment in these assets. As of December 31, 2002, we have recorded regulatory assets that are currently subject to recovery in future rates of approximately $360.3 million. Of this amount, $198.9 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs, including debt issuance costs, deferred employee benefit costs, deferred plant costs and coal contract settlement costs.
In a competitive environment, we may not be able to fully recover our entire investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net utility income will be lower than our historical net utility income has been unless we compensate for the loss of such income with other measures.
EPA New Source Review
The Environmental Protection Agency (EPA) is conducting an enforcement initiative at a number of coal-fired power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA has requested information from us under Section 114(a) of the Clean Air Act (Section 114). A Section 114 information request requires us to provide responses to specific EPA questions regarding certain projects and maintenance activities that the EPA believes may have violated the New Source Performance Standard and New Source Review requirements of the Clean Air Act. The EPA contends that power plants are required to update emission controls at the time of major maintenance or capital activity. We believe that maintenance and capital activities performed at our power plants are generally routine in nature and are typical for the industry. We are complying with this information request, but cannot predict the outcome of this investigation at this time. Should the EPA determine to take action, the resulting additional costs to comply could be material. We would expect to seek recovery through rates of any settlement amounts.
The EPA has initiated civil enforcement actions against other unaffiliated utilities as part of its initiative. Settlement agreements entered into in connection with some of these actions have provided for expenditures to be made over extended time periods.
Superfund Sites
In December 1999, we were identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). Based upon previous experience and the limited nature of our business transactions with the previous owners of the site, our obligation, if any, at the Kansas City site is not expected to have a material impact on our financial position or results of operations.
Nuclear Decommissioning
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 decommissioning. These plans are designed so that funds required for decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.
We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.
The KCC reviews our decommissioning fund financial plans in two phases. Phase one is the approval of the decommissioning study, the current year dollar amount and the future year dollar amount. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing its plans of how to fund the future year dollar amount for the pro rata share of the plant.
On February 25, 2002, we filed an application with the KCC to modify the funding schedule to reflect an assumed life of Wolf Creek through 2045 (see Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation”). This modification was granted on March 8, 2002. The filing reflects the current estimate in 1999 dollars of $221 million, but a future estimate in 2045 through 2054 of $1.28 billion. An updated decommissioning and dismantlement cost estimate was filed with the KCC on August 30, 2002. Costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied upon the site-specific, technical information developed in 1999, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. We anticipate a KCC order on the August 2002 decommissioning study in the second quarter of 2003. The actual decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.
We will file a funding schedule to reflect the KCC’s order on the August 2002 decommissioning study by the end of the second quarter of 2003 and anticipate a KCC order on the funding schedule in the third quarter of 2003.
Decommissioning costs are currently being charged to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the March 8, 2002 funding schedule. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek as determined by the KCC through 2045. The NRC requires that funds to meet its decommissioning funding assurance requirement be in our 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 results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.
Amounts expensed approximated $3.85 million in 2002 and will remain unchanged through 2044, subject to the August 2002 decommissioning cost review and revised funding schedule to be filed in the second quarter of 2003. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.56%.
Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $63.5 million at December 31, 2002 and $66.6 million at December 31, 2001. The balance in the trust fund decreased from 2001 to 2002 due to the decline in the market value of equity securities held in the trust. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.
Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized and depreciated over the appropriate period as part of the cost of the related tangible long-lived assets. The adoption of SFAS No. 143 will not impact income. Any income effects are offset by a regulatory asset created pursuant to SFAS No. 71. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
We adopted SFAS No. 143 on January 1, 2003, which required us to recognize and estimate 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. These amounts were estimated based on the calculation guidelines of SFAS No. 143. 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.
Monitored Services
Impairment Charges
Effective January 1, 2002, we adopted SFAS No. 142 and SFAS No. 144. SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. The completion of the impairment tests, based upon a valuation performed by an independent appraisal firm, as of January 1, 2002, indicated that the carrying values of goodwill at Protection One and Protection One Europe had been impaired and impairment charges were recorded as discussed below.
Another impairment test of Protection One’s goodwill and customer accounts was completed as of July 1, 2002 (the date selected for Protection One’s annual impairment test), with the independent appraisal firm providing
the valuation of the estimated fair value of Protection One’s reporting units, and no impairment was indicated. Protection One’s stock price declined after regulatory orders were issued (see Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation”), including the KCC’s December 23, 2002, order. As a result, Protection One retained the independent appraisal firm to perform an additional valuation of Protection One’s reporting units so it could perform an impairment test as of December 31, 2002, which resulted in the additional impairment charge discussed below.
SFAS No. 144 established a new approach to determining whether our customer account asset is impaired. The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of the reporting unit, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then we are required to mark the customer account asset down to fair value, by recording an impairment, to the extent fair value is less than our book value. To the extent net book value is less than fair value, no impairment would be recorded.
The new rule substantially reduces the net undiscounted cash flows for customer account impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16 year remaining life of the goodwill to the nine year remaining life of customer accounts for impairment evaluation purposes. Using these new guidelines, we determined that there was an indication of impairment of the carrying value of the customer accounts and an impairment charge was recorded as discussed below.
To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, we recorded a charge in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.
The impairment charge for goodwill recorded in the first quarter of 2002 is reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts is reflected in our consolidated statement of income as an operating expense. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002.
Protection One completed an additional impairment test of goodwill as of December 31, 2002. We recorded an impairment charge of $79.7 million, net of tax benefit and minority interests, in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill of Protection One’s North America segment, which is reflected in our consolidated statement of income as an operating expense.
We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill of Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe, which is reflected in our consolidated statement of income as an operating expense. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.
These charges for the year ended December 31, 2002, are detailed as follows:
The investment at cost in customer accounts at December 31, 2002 was $1.1 billion and at December 31, 2001 was approximately $1.4 billion. Accumulated amortization of the investment in customer accounts at December 31, 2002 was $678.9 million and at December 31, 2001 was $614.5 million. We recorded approximately $83.3 million of customer account amortization expense during the year ended December 31, 2002, $148.0 million during the same period of 2001 and $158.7 million during the year ended December 31, 2000. Customer account amortization expense is reduced primarily as a result of the impairment charge that reduced our customer account balance. The table below reflects the estimated aggregate customer account amortization expense for 2003 and each of the four succeeding fiscal years.
We are required to perform impairment tests for long-lived assets prospectively for our monitored services segment as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested upon certain triggering events, which include recurring operating losses, adverse business conditions, adverse regulatory rulings, declines in market values and other matters that negatively impact value. Given the potentially negative implications from the KCC’s December 23, 2002 order, and the subsequent decline in Protection One’s stock price, Protection One tested its goodwill for impairment at December 31, 2002, which resulted in the additional impairment charge discussed above. If future impairment tests for either goodwill or customer accounts indicate fair value is less than book value, we will be required to recognize additional impairment charges on these assets in the future. Any such impairment charges could be material.
Change in Estimate of Customer Life
During the first quarter of 2002, Protection One evaluated the estimated life and amortization rates for customer accounts, based on the results of a lifing study performed by a third party appraisal firm in the first quarter of 2002. The report showed Protection One’s North America customer pool can expect a declining revenue stream over the next 30 years with an estimated average remaining life of 9 years. Protection One’s Multifamily pool can expect a declining revenue stream over the next 30 years with an estimated average remaining life of 10 years. Taking into account the results of the lifing study and the inherent expected declining revenue streams for the North America and Multifamily customer pools, in particular the first five years, Protection One adjusted the rate of amortization on customer accounts for its North America and Multifamily customer pools to better match the rate and period of amortization expense with the expected decline in revenues. In the first quarter of 2002, Protection One changed its amortization rate for its North America pool to a 10-year 135% declining balance method from a 10-year 130% declining balance method. For the Multifamily pool, Protection One will continue to amortize on a straight-line basis utilizing a shorter nine year life. Protection One accounted for these amortization changes prospectively beginning January 1, 2002, as a change in estimate. These changes in estimates increased amortization expense for the year ended December 31, 2002 by approximately $0.8 million, net of $0.5 million tax.
Attrition
Customer attrition has a direct impact on the results of our monitored services operations since it affects its revenues, amortization expense and cash flow. Attrition is defined as a ratio, the numerator of which is the gross
number of lost customer accounts for a given period, net of the adjustments described below, and the denominator of which is the average number of accounts for a given period. In some instances, estimates are used to derive attrition data. Adjustments are made to lost accounts primarily for the net change, either positive or negative, in the wholesale base and for accounts that are covered under a purchase price holdback and are “put” back to the seller. The gross accounts lost during a period are reduced by the amount of the guarantee provided for in the purchase agreements with sellers. In some cases, the amount of the purchase holdback may be less than actual attrition experience. Adjustments to lost accounts for purchase holdbacks is expected to be lower in the future because Protection One is purchasing fewer accounts in the types of transactions that create holdbacks and it has extinguished a substantial portion of its purchase holdback reserve. The gross accounts lost during a period are not reduced by “move in” accounts, which are accounts where a new customer moves into the premises equipped with a Protection One security system and vacated by a prior customer, or “competitive takeover” accounts, which are accounts where the owner of a premise monitored by a competitor requests that we provide monitoring services.
Actual attrition experience shows that the relationship period with any individual customer can vary significantly. Customers’ service can be discontinued for a variety of reasons, including relocation, non-payment, customers’ perception of value and competition. A portion of the acquired customer base can be expected to discontinue service every year. Any significant change in the pattern of historical attrition experience would have a material effect on our results of operations from monitored services.
Attrition is monitored each quarter based on an annualized and trailing twelve-month basis. This method utilizes the average customer account base for the applicable period in measuring attrition. Therefore, in periods of customer account growth, customer attrition may be understated and in periods of customer account decline, customer attrition may be overstated.
Customer attrition for the years ended December 31, 2002, 2001 and 2000 is summarized below.
Our monitored services segment had a net decrease of 62,656 customers from December 31, 2001 to December 31, 2002. Attrition decreased at Protection One in 2002 compared to 2001 for a variety of reasons, including:
•
An aggressive campaign dubbed “Save Our Subscribers,” designed to retain existing customers.
•
An emphasis on customer service and attrition reduction by branch and monitoring center personnel.
•
Legal action taken against competitors who illegally solicit our customers.
Related Party Transactions
Below, we describe significant transactions between us and Westar Industries and some of our other subsidiaries and related parties. We have disclosed these significant transactions even if they have been eliminated in the preparation of our consolidated results and financial position.
ONEOK Shared Services Agreement
We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support, meter reading and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses.
ONEOK gave us notice of termination effective December 2003 of this shared services agreement. We expect termination of this agreement will increase our annual costs to provide these services by approximately $11 million to $13 million.
Protection One Shared Services Agreement
We provide administrative services to Protection One pursuant to services agreements, including accounting, tax, audit, human resources, legal, purchasing, facilities and technology services. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $3.9 million in 2002, $8.1 million in 2001 and $7.3 million in 2000. These intercompany charges have been eliminated in consolidation.
Westar Energy and Protection One have entered into an amended service agreement that stipulates that if Westar Energy sells its interest in Protection One, Westar Energy and Protection One will negotiate, in good faith, the terms and conditions for continuation of the services during an agreed-upon transition period. This agreement is subject to KCC approval, which has not yet been received.
Transactions Between Westar Industries and Subsidiaries
Protection One Credit Facility
Westar Industries is the lender under Protection One’s senior credit facility. The senior credit facility was amended to increase the capacity from $155 million to $280 million during the year ended December 31, 2002. On August 26, 2002, the senior credit facility was further amended to extend the maturity date to January 5, 2004. On March 11, 2003, the KCC limited the amount of the credit facility to $228.4 million, authorized us to fund the facility and extend the term of the facility to January 5, 2005 and required the facility to be paid in full and terminated upon the disposition of all or part of our investment in Protection One. We are in discussions with Protection One about the extension of the facility and we intend to renew the facility through January 5, 2005, should such renewal be necessary to provide Protection One with continued liquidity. For further information, see Note 34 of the Notes to Consolidated Financial Statements, “Subsequent Events.”
As of December 31, 2002, $215.5 million was drawn under the facility. The remaining availability under this facility as of December 31, 2002 was $64.5 million. At March 14, 2003, Protection One had outstanding borrowings of $215.5 million and $12.9 million of remaining capacity. Amounts outstanding, accrued interest and facility fees have been eliminated in our consolidated financial statements.
Purchases of Securities
Westar Industries, Protection One and we have purchased our and Protection One debt securities and preferred stock in the open market. These repurchases have been accounted for as retirements on a consolidated basis. The table below summarizes these transactions for the years ended December 31, 2002, 2001 and 2000.
(a) Represents the fair value of a call option associated with our putable/callable notes (see Note 14 of the Notes to Consolidated Financial Statements, “Call Option”).
(b) In 2001, $37.9 million of these bonds were purchased by Westar Industries and $27.6 million of these were transferred to Protection One in exchange for cash.
(c) In 2000, $170.0 million of these bonds were purchased by Westar Industries and $103.9 million of these were transferred to Protection One in exchange for cash and the settlement of certain intercompany payables and receivables.
See Note 26 of the Notes to Consolidated Financial Statements, “Gain on Debt Retirements,” for information about a change in accounting treatment that requires that gains and losses arising from the purchases and sales of these securities be recorded as other income rather than as an extraordinary item. See Note 34 of the Notes to Consolidated Financial Statements, “Subsequent Events - Purchase of Stock from Protection One” and “Subsequent Events - Purchases of Debt Securities,” for information regarding purchases of securities that have occurred during 2003.
Tax Sharing Agreement
We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes so long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $13.5 million for tax year 2001 and $7.4 million for tax year 2000. On March 11, 2003, the KCC issued an order that allows us to make a cash payment to Protection One of approximately $20 million for tax year 2002.
Financial Advisory Services
Protection One entered into an agreement pursuant to which it paid a quarterly fee to Westar Industries for financial advisory services equal to 0.125% of its consolidated total assets at the end of each quarter. This agreement was approved by the independent members of Protection One’s board of directors. Protection One incurred approximately $3.6 million of such fees during the year ended December 31, 2002. These amounts have been eliminated in our consolidated financial statements. This agreement was terminated effective September 30, 2002.
Loans to Officers
During 2001 and 2002, we extended loans to our officers for the purpose of purchasing shares of our common stock. The officers are personally liable for the repayment of the loans, which are unsecured and bear interest, payable quarterly, at a variable rate equal to our short-term borrowing rate. The loans mature on December 4, 2004. The aggregate balance outstanding at December 31, 2002 was approximately $1.8 million, which is classified as a reduction to shareholders’ equity in the accompanying consolidated balance sheets. For the year ended December 31, 2002, we recorded approximately $97,000 in interest income on these loans. No additional loans will be made as a result of federal legislation that became effective July 30, 2002.
Transactions Between Westar Energy and KGE
We perform KGE’s cash management function, including cash receipts and disbursements. An intercompany account is used to record net receipts and disbursements between us and KGE. KGE’s net amount payable from affiliates approximated $24.1 million at December 31, 2002, and the net amount receivable from affiliates approximated $17.3 million at December 31, 2001. These intercompany charges have been eliminated in consolidation.
We provide all employees utilized by KGE. We allocate certain operating expenses to KGE. 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.
Transactions with Protection One
During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers’ findings. This transaction was completed during June 2002. We recognized a loss of $2.6 million on this transaction and we expected to realize annual operating cost savings of approximately $0.9 million. The cost savings will be treated as a regulatory liability in accordance with a March 26, 2002, KCC order. For the year ended December 31, 2002, we recorded $0.5 million in cost savings as a regulatory liability.
Protection One Europe
On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held by a subsidiary of Protection One, for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Cash proceeds from the transaction were used to reduce the outstanding balance owed to Westar Industries on Protection One’s revolving credit facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected.
Hedging Activity
We use financial and physical instruments to hedge 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 fuel commodity price market risk, we use hedging arrangements to reduce our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent upon the market prices and the extent and effectiveness of any hedging arrangements into which we enter.
See Note 6 of the Notes to Consolidated Financial Statements, “Financial Instruments, Energy Trading and Risk Management - Derivative Instruments and Hedge Accounting - Hedging Activities,” for detailed information regarding hedging relationships and an interest rate swap we entered into during the third quarter of 2001.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Price Risks
Our hedging and trading activities involve risks, including commodity price risk, equity 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. These commodities have experienced price volatility in the past and can be expected to do so in the future. This volatility may increase or decrease future earnings.
Equity price risk is the risk we may be exposed to based on changes in the market value of our equity securities.
Interest rate risk is the risk of loss associated with movements in market interest rates. During 2002, we used an interest rate swap to manage our exposure to variable interest rates. The swap converted $500 million of variable rate debt to a fixed rate. In the future, we may continue to use swaps or other financial instruments to manage interest rate risk.
Credit risk is the risk of loss resulting from non-performance by a counterparty of its contractual obligations. We have exposure to credit risk and counterparty default through our retail, power marketing and trading activities. We maintain credit policies intended to reduce overall credit risk and actively monitor these policies to reflect changes and scope of operations. We employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements from counterparties that allow for some of the offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Results actually achieved from hedging and trading activities could vary materially from intended results and could materially affect our financial results depending on the success of our credit risk management efforts.
Commodity Price Exposure
We engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil. We use a variety of financial instruments, including forward contracts, options and swaps and trade energy commodity contracts daily. We also use hedging techniques to manage overall fuel expenditures. We procure physical product under fixed price agreements and spot market transactions.
We are involved in trading activities primarily to reduce risk from market fluctuations, capitalize on our market knowledge and enhance system reliability. 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 financial position or results of operations.
We manage and measure the market price risk exposure of our trading portfolio using a variance/covariance value-at-risk (VaR) model. VaR measures the predicted worst-case loss at a specific confidence level over a specified period of time. In addition to VaR, we employ additional risk control processes such as stress testing, daily loss limits, and commodity position limits. We expect to use the same VaR model and control processes in 2003.
The use of the VaR method requires a number of key assumptions, including the selection of a confidence level for losses and the estimated holding period. We express VaR as a potential dollar loss based on a 95%
confidence level using a one-day holding period. The calculation includes derivative commodity instruments used for both trading and risk management purposes. The VaR amounts for 2002 and 2001 were as follows:
We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce overall credit risk. There can be no assurance that the employment of VaR, or other risk management tools we employ, will eliminate the risk of loss.
We are also exposed to commodity price changes outside of trading activities. We use derivatives 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 power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to changing market prices that may adversely impact our financial position and results of operations. 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 2001 to 2002, we experienced a 10% decrease in the average price per MWh of electricity purchased for utility operations. Purchased power market volatility could be greater than the average price decrease indicates. If we were to have a 10% increase in our purchased power price from 2002 to 2003, given the amount of power purchased for utility operations during 2002, we would have exposure of approximately $3.5 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices.
We use a mix of various fossil fuel types, including coal, natural gas and oil, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk associated with this commodity type. During 2002, we experienced an approximate 2% increase, or $0.056 per MMBtu, in our average cost for natural gas purchased for utility operations. We decreased our gas usage by 1.9 million MMBtu compared to the amount burned in 2001. Due to the volatility of natural gas prices, we have begun to increasingly utilize our ability to switch to lower cost fuel types as the market allows. We expect that exposure to natural gas price changes will not be material in 2003 due to our natural gas hedge that has fixed the price of our gas through July 2004.
We use uranium to fuel our nuclear generating station and have on hand or under contract 100% of Wolf Creek’s uranium, uranium conversion and uranium enrichment needs for 2003. We have on hand or under contract 76% of the uranium and uranium conversion and 80% of the uranium enrichment required for operation of Wolf Creek through March 2008. The balance is expected to be obtained through spot market and contract purchases, which means we will be exposed to the price risk associated with these components.
Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically from year to year based on the individual fuel’s availability, price, deliverability, unit outages and nuclear refueling. Our customers’ electricity usage could also vary dramatically year to year based on the weather or other factors.
Interest Rate Exposure
We had approximately $523.4 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2002. A 100 basis point change in each debt series’ benchmark rate, used to set the rate for such series would impact net income on an annualized basis by approximately $2.5 million after tax.
Under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our consolidated balance sheet reflects the current fair value of the free standing portion of the call option as discussed in Note 14 of the Notes to Consolidated Financial Statements, “Call Option.” The amount of our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. Related to the call option, for the year ended December 31, 2002, we recorded a non-cash mark-to-market charge of $23.7 million, net of $15.7 million tax benefit, to reflect the fair value of the call option associated with the retired notes. We intend to repurchase or provide for the repayment of all or a portion of these notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.
Foreign Currency Exchange Rates
We have foreign operations with functional currencies other than the U.S. dollar. As of December 31, 2002, the unrealized loss on currency translation was approximately $2.5 million pretax. A 10% change in the currency exchange rates would not have a material effect on other comprehensive income.
Equity Price Risk
During 2002, we were not substantially exposed to equity price risk. As discussed in Note 4 of the Notes to Consolidated Financial Statements, “Changes in ONEOK Ownership,” we sold a substantial portion of our equity investment in ONEOK. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” and mark to market its fair value through other comprehensive income.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE
Report of Independent Public Accountants
Financial Statements:
Westar Energy, Inc. and Subsidiaries:
Consolidated Balance Sheets, December 31, 2002 and 2001
Consolidated Statements of Income (Loss) for the years ended
December 31, 2002, 2001 and 2000
Consolidated Statements of Comprehensive Income (Loss) for the years ended
December 31, 2002, 2001 and 2000
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000
Consolidated Statements of Shareholders’ Equity for the years ended
December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
Financial Schedules:
Schedule II-Valuation and Qualifying Accounts
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in our consolidated financial statements and schedules presented:
I, III, IV, and V.
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Shareholders of
Westar Energy, Inc.
Topeka, Kansas
We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Part IV, 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 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 23 to the financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Accounting for Goodwill and Other Intangible Assets and Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. As discussed in Note 2 to the financial statements, on January 1, 2001 the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. As discussed in Note 2 to the financial statements, on January 1, 2000, the Company adopted Staff Accounting Bulletin 101, Revenue Recognition.
DELOITTE & TOUCHE LLP
Kansas City, Missouri,
April 11, 2003
WESTAR ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTAR ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002
1. DESCRIPTION OF BUSINESS
Westar Energy, Inc., a Kansas corporation incorporated in 1924, operates the largest electric utility in Kansas and owns interests in monitored security businesses and other investments. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” or similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc. alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 647,000 customers in Kansas. We also provide monitored security services to over 1.1 million customers in the United States and Europe. ONEOK, Inc. (ONEOK), in which we owned an approximate 45% interest at December 31, 2002, (reduced to an approximate 27.5% interest at March 14, 2003) provides natural gas transmission and distribution services to approximately 1.9 million customers in Kansas, Oklahoma and Texas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.
Westar Energy and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek) our nuclear powered generating facility.
Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One Inc. (Protection One), Protection One Europe, ONEOK and our other non-utility businesses. Protection One, a publicly traded, approximately 88%-owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns an approximate 99.8% interest.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). Our consolidated financial statements include all operating divisions and majority owned subsidiaries for which we maintain controlling interests. Common stock investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation.
Use of Management’s Estimates
The preparation of consolidated financial statements requires management 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, depreciation, revenue recognition, investments, customer accounts, goodwill, intangible assets, income taxes, pensions and other post retirement and post-employment benefits, 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 obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. Our earnings would be reduced by the net amount calculated from the table below, net of applicable income taxes. Regulatory assets and liabilities reflected in our consolidated balance sheets are as follows:
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Recoverable income taxes: Recoverable income taxes represent amounts due from customers for accelerated tax benefits that have been previously flowed through to customers and are expected to be recovered in the future as the accelerated tax benefits reverse. This item will be recovered over the life of the utility plant.
•
Debt issuance costs: Debt reacquisition expenses are amortized over the remaining term of the reacquired debt or, if refinanced, the term of the new debt. Debt issuance costs are amortized and will be recovered over the term of the associated debt.
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Deferred employee benefit costs: Deferred employee benefit costs represent post-retirement and post-employment expenses in excess of amounts paid that are to be recovered over a period of five years as authorized by the Kansas Corporation Commission (KCC).
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Deferred plant costs: Deferred plant costs relate to the Wolf Creek nuclear generating facility. For further information, see “- Depreciation,” discussed below.
•
2002 ice storm costs: Restoration costs associated with an ice storm that occurred in January 2002. See Note 30 for additional information regarding the ice storm.
A return is allowed on coal contract settlement costs (included in “Other regulatory assets” in the table above) and on the 2002 ice storm costs.
Cash and Cash Equivalents
We consider highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Restricted Cash
Restricted cash consists of cash irrevocably deposited in trust for debt repayments, cash collateralizing Protection One’s workers’ compensation obligations, a prepaid capacity and transmission agreement, letters of credit, surety bonds and escrow arrangements as required by certain letters of credit, and various other deposits.
Inventories and Supplies
Inventories and supplies for our utility business are stated at average cost. Inventories for our monitored services segment, comprised of alarm systems and parts, are stated at the lower of average cost or market.
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 5.95% in 2002, 9.01% in 2001 and 7.39% in 2000. The cost of additions to utility plant and replacement units of property is capitalized. Interest capitalized into construction in progress was $2.2 million in 2002, $8.7 million in 2001 and $9.4 million in 2000.
Maintenance costs and replacement of minor items of property are charged to expense as incurred. Incremental costs incurred during scheduled Wolf Creek refueling and maintenance outages are deferred and amortized monthly over the unit’s operating cycle, normally about 18 months. For utility plant, when units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation.
Depreciation
Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or 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 2.66% during 2002, 3.03% during 2001 and 2.99% during 2000.
In its rate order of July 25, 2001, the KCC extended the estimated service life for certain of our generating assets, including Wolf Creek and the LaCygne 2 generating station, for regulatory rate making purposes. The estimated retirement date for Wolf Creek was extended from 2025 to 2045, although our operating license for Wolf Creek expires in 2025, and the estimated retirement date for LaCygne 2 was extended to 2032, although the term of our lease for LaCygne 2 expires in 2016. On April 1, 2002, we adopted the new depreciation rates as prescribed in the KCC order. We continue to depreciate Wolf Creek over the term of our operating license, and we continue to depreciate LaCygne 2 over the term of our lease. We have created a regulatory asset, included under “Deferred plant costs” in the above table, for the amount that our depreciation expense exceeds our regulatory depreciation expense.
On an annual basis, our depreciation expense will be reduced by approximately $30.0 million as a result of these extensions. If our generating license for Wolf Creek is not renewed or the term of our lease for LaCygne 2 is not extended, we will need to seek relief from the KCC to recover the remaining cost of these assets.
Non-utility property, plant and equipment is depreciated over the estimated useful lives of the related assets. We periodically evaluate our depreciation rates considering the past and expected future experience in the operation of our facilities.
Depreciable lives of property, plant and equipment are as follows:
Nuclear Fuel
Our share of the cost of nuclear fuel in 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 cost of sales based upon the quantity of heat produced (MMBtu) for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $25.2 million at December 31, 2002 and $35.6 million at December 31, 2001. Spent fuel charged to cost of sales was $17.8 million in 2002, $22.1 million in 2001 and $19.6 million in 2000.
Customer Accounts
Customer accounts are stated at cost and are amortized over the estimated customer life. The cost includes amounts paid to dealers and the estimated fair value of accounts acquired in business acquisitions. Internal costs incurred in support of acquiring customer accounts are expensed as incurred.
Protection One’s and Protection One Europe’s amortization rates consider the average estimated remaining life and historical and projected attrition rates. The amortization method for each customer pool is as follows:
In accordance with SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,” long-lived assets held and used by Protection One and Protection One Europe are evaluated for recoverability on a periodic basis or as circumstances warrant. An impairment would be recognized when the undiscounted expected future operating cash flows by customer pool derived from customer accounts is less than the carrying value of capitalized customer accounts and related goodwill. See Note 23 for information regarding SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets,” which replaces SFAS No. 121 as of January 1, 2002.
Due to the customer attrition experienced in 2002, 2001 and 2000, the decline in market value of Protection One’s publicly traded equity and debt securities and recurring losses, Protection One and Protection One Europe performed impairment tests on their customer account assets and goodwill in 2002, 2001 and 2000. These tests indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill. See Note 23 for a discussion of the impairment recorded on these assets during 2002 pursuant to the adoption of new accounting principles.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One and Protection One Europe. Protection One and Protection One Europe changed their estimated goodwill life from 40 years to 20 years as of January 1, 2000. For 2001 and 2000, remaining goodwill, net of accumulated amortization, was amortized over its remaining useful life based on a 20-year life.
For 2001 and 2000, the carrying value of goodwill was included in the evaluations of recoverability of customer accounts. No reduction in the carrying value was necessary at December 31, 2001 or 2000.
Effective as of January 1, 2002, we adopted SFAS No. 142, “Accounting for Goodwill and Other Intangible Assets” and no longer amortize goodwill. We are subject to the annual goodwill impairment test. See Note 23 for information regarding the effect of adopting SFAS No. 142.
Cash Surrender Value of Life Insurance
The following amounts related to corporate-owned life insurance policies (COLI) are recorded 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 other income approximated $3.6 million in 2002, $2.7 million in 2001 and $0.8 million in 2000.
Minority Interests
Minority interests represent the minority shareholders’ proportionate share of the shareholders’ equity and net losses of Protection One and Protection One Europe.
Revenue Recognition
Energy Sales
Energy sales are recognized as delivered and include an estimate for energy delivered but unbilled at the end of each year. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets.
We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results.
Monitored Services Revenues
Monitored services revenues are recognized when security services are provided. System installation revenues, sales revenues on equipment upgrades and direct and incremental costs of installations and sales are deferred for residential customers with monitoring service contracts. For commercial customers, revenue recognition is dependent upon each specific customer contract. In instances when the company passes title to a system unaccompanied by a service agreement or the company passes title at a price that it believes is unaffected by an accompanying but undelivered service, the company recognizes revenues and costs in the period incurred. In cases where the company retains title to the system or it prices the system lower than it otherwise would because of an accompanying service agreement, the company defers and amortizes revenues and direct costs.
Deferred system and upgrade installation revenues are recognized over the expected life of the customer utilizing an accelerated method for residential and commercial customers and a straight-line method for Protection One’s Multifamily customers. Deferred costs in excess of deferred revenue are recognized over the initial contract term, utilizing a straight-line method, typically two to three years for residential systems, five years for commercial systems and five to ten years for Multifamily systems. To the extent deferred costs are less than deferred revenues, such costs are recognized over the estimated life of the customer relationship.
Deferred revenues also result from customers who are billed for monitoring and extended service protection in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. Revenues from monitoring activities are recognized in the period such services are provided.
Income Taxes
Our consolidated financial statements use the liability method to reflect income taxes. Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. We amortize deferred investment tax credits over the lives of the related properties.
Foreign Currency Translation
The assets and liabilities of our foreign operations are translated into U.S. dollars at current exchange rates, and revenues and expenses are translated at average exchange rates.
Cumulative Effects of Accounting Changes
Accounting for Goodwill
Effective January 1, 2002, we adopted SFAS No. 142. See Note 23 for the cumulative effect of this adoption.
Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in some of our fossil fuel and electricity purchases and sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheets as either an asset or liability measured at fair value. Changes in a derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met, in which case changes are reflected in other comprehensive income. Cash flows from derivative instruments are presented in net cash flows from operating activities.
Derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales are classified as energy trading contracts on our consolidated balance sheets. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on
January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income for 2001 as a cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under “- Revenue Recognition - Energy Sales.” Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings.
Revenue Recognition
In the fourth quarter of 2000, we adopted Staff Accounting Bulletin (SAB) No. 101, “Revenue Recognition,” which had a retroactive effective date of January 1, 2000. The impact of this accounting change generally required deferral of certain monitored security services sales for installation revenues and direct sales-related expenses. Deferral of these revenues and costs is generally necessary when installation revenues have been received and a monitoring contract to provide future service is obtained.
The cumulative effect of this change in accounting principle was a charge to income in 2000 of approximately $3.8 million, net of $1.1 million tax benefit, and is related to changes in revenue recognition at Protection One Europe. Prior to the adoption of SAB No. 101, Protection One Europe recognized installation revenues and related expenses upon completion of the installation.
Accounting Changes
Stock Based Compensation
In December 2002, Financial Accounting Standards Board (FASB) issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” which amends SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, it amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. This statement requires that companies follow the prescribed format and provide the additional disclosures in their annual reports for fiscal years ending after December 15, 2002. We apply the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” as allowed by SFAS Nos. 123 and 148, and related interpretations in accounting for our stock-based compensation plans, as described in Note 15. We have adopted the disclosure requirements of SFAS No. 148.
For purposes of the pro forma disclosures required by SFAS No. 148, the estimated fair value of the options is amortized to expense over the options’ vesting period. Under SFAS No. 123, compensation expense would have been $0.8 million in 2002 and $1.1 million in 2000. We would have recorded income of $0.5 million in 2001 under SFAS No. 123. Information related to the pro forma impact on our earnings and earnings per share follows.
Accounting for Energy Trading Contracts
In October 2002, the FASB, through the Emerging Issues Task Force (EITF), issued Issue No. 02-03, which rescinded Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, all new contracts that would otherwise have been accounted for under Issue No. 98-10 and that do not fall within the scope of SFAS No. 133 can no longer be marked-to-market and recorded in earnings as of October 25, 2002. We are not affected by this change in accounting principle and are not required to reclassify any of our contracts. EITF Issue No. 02-03 also requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. We began to classify our energy trading contracts on a net basis during the third quarter of 2002.
On July 1, 2002, we began reporting mark-to-market gains and losses on energy trading contracts on a net basis, whether realized or unrealized, in our consolidated income statements. Prior to July 1, 2002, we reported gains on these contracts in sales and losses in cost of sales in our consolidated income statements. See Note 6 for additional information on the effects of the accounting change.
Gains and Losses from Extinguishment of Debt
Effective July 1, 2002, we adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which prohibits treating gains and losses associated with extinguishments resulting from a company’s risk management strategy as extraordinary. See Note 26 for additional information on this pronouncement.
During the last three years, Protection One and our debt securities were repurchased in the open market and gains were recognized on the retirement of these debt securities. We recognized $12.0 million, net of $6.3 million tax, in 2002; $23.2 million, net of $12.6 million tax, in 2001; and $49.2 million, net of $26.5 million tax, in 2000.
Accounting for Guarantees
In November 2002, FASB issued Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which provides guidance for accounting for guarantees. For any guarantee entered into after November 2002, a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Any future guarantee that we enter into will be accounted for as a liability.
In 1998, we issued a financial guarantee of an obligation of Onsite Energy Corporation under which our maximum liability was $1.3 million. This guarantee was released in the first quarter of 2003.
Consolidation of Variable Interest Entities
In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51.” This interpretation provides guidance related to identifying variable interest entities (previously known generally as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required when FIN No. 46 becomes effective if it is reasonably possible that a company will consolidate or disclose information about a variable interest entity when it initially applies FIN No. 46. This interpretation must be applied immediately to variable interest entities created or obtained after January 31, 2003. For those variable interest entities created or obtained on or before January 31, 2003, we must apply the provisions of FIN No. 46 in the third quarter of 2003. We are currently evaluating the effect of FIN No. 46.
Dilutive Shares
Basic earnings per share applicable to common stock are based on the weighted average number of common shares outstanding and vested during the period reported. Diluted earnings per share include the effect of potential issuances of common shares resulting from the assumed vesting of all outstanding restricted share units (RSU) and exercise of all outstanding stock options issued pursuant to the terms of our stock-based compensation plans. The dilutive effect of stock-based compensation and stock options is computed using the treasury stock method. The number of potential dilutive securities was 676,329 shares for 2002, 963,749 shares for 2001 and 629,016 shares for 2000. The potentially dilutive securities for 2002 and 2001 were not included in the computation of diluted earnings per share, since to do so would have been antidilutive.
Diluted earnings per share amounts shown in the accompanying financial statements reflect the inclusion of non-vested restricted share awards and the effect of stock options outstanding. The following represents a reconciliation of the weighted average number of common shares outstanding for basic and dilutive purposes.
Supplemental Cash Flow Information
Cash paid for interest and income taxes for each of the three years ended December 31, are as follows:
Reclassifications
Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings
On November 27, 2000, Westar Energy and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a $41.2 million reduction in KGE’s rates and an $18.5 million increase in Westar Energy’s rates.
On August 9, 2001, Westar Energy and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased Westar Energy’s rates by an additional $7.0 million. The $41.2 million rate reduction in KGE’s rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned “Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas.” On March 8, 2002, the Court of Appeals upheld the KCC orders. On April 8, 2002, we filed a petition for review of the decision of the Court of Appeals with the Kansas Supreme Court. Our petition for review was denied on June 12, 2002.
KCC Orders and Debt Reduction and Restructuring Plan
November 8, 2002 KCC Order
On November 8, 2002, the KCC issued an order addressing our proposed financial plan presented to the KCC on November 6, 2001 and subsequently amended on January 29, 2002. The order contained the following findings and directions:
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The order directed us to reverse certain transactions, including reversing certain intercompany accounting entries so certain capital contributions by us to Westar Industries are reflected as an intercompany payable owed by Westar Industries to us, and reversing all transactions in 2002 recorded as equity investments by us in Westar Industries so such transactions are reflected as intercompany payables owed by Westar Industries to us.
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The order directed us to submit a plan within 90 days for restructuring our organizational structure so that our KPL electric utility business operating as a division of us is placed in a separate subsidiary. The plan required us to include the process for restructuring, an analysis of whether the restructuring is consistent with our present debt indentures and loan agreements, and if not, the necessary amendments to proceed with the restructuring. The restructuring plan was required to be accompanied by an updated cost allocation manual to track costs and investments attributable to our regulated electric utility and non-regulated activities. Following approval of the restructuring plan and the updated cost allocation manual, we will be required to provide the KCC with separate quarterly financial statements for us and our electric utility operations. We filed a plan with the KCC on February 6, 2003 as discussed below in “- February 6, 2003 Debt Reduction and Restructuring Plan.”
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The order directed us to provide a written explanation if the amount of debt secured by utility assets that we transfer to the new utility subsidiary exceeds $1.5 billion.
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The order directed us to reduce our consolidated debt, to consider certain actions for reducing our consolidated debt, and to provide expert testimony supporting any decision to reject a suggested action. For the two years beginning on the date we submit our restructuring plan, we are required to reduce utility debt by at least $100 million annually. The suggested actions include payments of $100 million each year from internally generated cash flow, the issuance of common stock, the sale of ONEOK stock, a reduction in, or elimination of, our dividend, and the sale of Protection One.
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The order initiated an investigation into the appropriate type, quantity, structure and regulation of the non-utility businesses with which our utility businesses may be affiliated.
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The order established standstill protections requiring that we seek KCC approval before we take certain actions, including making any loan to, investment in or transfer of cash in excess of $100,000 to a non-utility affiliate, entering into any agreement with a non-utility affiliate where the value of goods or services exchanged exceeds $100,000, investing by us or an affiliate of more than $100,000 in an existing or new non-utility business, transferring any non-cash assets or intellectual property to any non-utility affiliate, issuing any debt, or selling any ONEOK stock without complying with the requirements of a July 9, 2002 KCC order. In addition, we must charge interest to non-utility affiliates at the incremental cost of their debt on outstanding balances of any existing or future inter-affiliate loans, receivables or other cash advances due us. These restrictions apply both to us and our KGE subsidiary.
On November 25, 2002, we filed a motion for reconsideration and clarification of some provisions of the order. In response, the KCC issued an order on December 23, 2002 as discussed below.
December 23, 2002 KCC Order
On December 23, 2002, the KCC issued an order modifying the requirements of the November 8, 2002 order concerning creation of a utility-only subsidiary and filing of a financial plan. The order directed that no later than August 1, 2003, our KPL utility division must be held within a utility-only subsidiary. The consolidated debt for all of our utility businesses, the KPL utility division and KGE, shall not exceed $1.67 billion.
February 6, 2003 Debt Reduction and Restructuring Plan
On February 6, 2003, we filed a Debt Reduction and Restructuring Plan (the Debt Reduction Plan) with the KCC outlining our plans for paying down debt and restructuring the company. The Debt Reduction Plan detailed items that have already been accomplished, including, among other things, that:
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Consistent with the KCC’s prior orders, we have terminated certain agreements and reversed certain intercompany transactions that might have prevented or impeded returning to being a stand-alone electric utility.
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We have sold a portion of our ONEOK stock and raised $300 million, the net proceeds of which we anticipate using to repurchase or provide for the repayment of all of the 6.25% senior unsecured notes that have a final maturity of August 15, 2018 and are putable and callable on August 15, 2003 (the putable/callable notes) and a portion of our 6.875% senior unsecured notes.
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Our board of directors has established a dividend policy that reduced our quarterly common dividend by 37% to a dividend rate of $0.19 per share for the first quarter of 2003.
In addition, the Debt Reduction Plan calls for:
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The sale of Protection One Europe.
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The sale of our interest in Protection One.
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The sale of all of our remaining shares of ONEOK preferred stock (21.8 million shares) and common stock (4.7 million shares). We anticipate that all remaining ONEOK securities will be liquidated by year-end 2004.
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The sale of other non-core and non-utility assets. We intend to dispose of these assets in an orderly fashion. While not expected to be significant in the Debt Reduction Plan, net proceeds from these dispositions will also be used for debt reduction.
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The potential issuance of equity securities in the second half of 2004, if needed to further reduce debt, following the disposition of all material non-utility and non-core assets.
February 10, 2003 KCC Order
On February 10, 2003, the KCC issued an order granting limited reconsideration of its December 23, 2002 order. The KCC stayed the requirement of the December 23, 2002 order that we form a utility-only subsidiary. The KCC also stated that the Debt Reduction Plan appears to make a good-faith effort to address the concerns expressed in the KCC’s prior orders and that the KCC needed additional time to review the Debt Reduction Plan prior to addressing other issues raised in our petition for reconsideration of the December 23, 2002 order.
The KCC staff and other parties to the KCC docket considering the Debt Reduction Plan have filed comments on the Debt Reduction Plan. The KCC has not yet established a procedural schedule for considering the Debt Reduction Plan and the related comments. We are unable to predict what action the KCC will take with respect to the Debt Reduction Plan.
March 11, 2003 KCC Order
On March 11, 2003, the KCC issued an order conditionally approving a partial stipulation entered into by us, Protection One and certain parties in the KCC docket considering the Debt Reduction Plan. The order, among other things, (a) authorized us to make a payment to Protection One of approximately $20 million for the 2002 tax year under the tax sharing agreement with Protection One, (b) authorized Westar Industries to extend the maturity date of the credit facility it provides to Protection One to January 5, 2005, (c) reduced the amount that may be advanced to Protection One under the credit facility to $228.4 million, (d) authorized us to pay approximately $1.0 million to Protection One as reimbursement for information technology services provided to us, and related costs incurred, by a subsidiary of Protection One, and (e) authorized us to pay approximately $3.4 million to Protection One as reimbursement for aviation services provided by a subsidiary of Protection One and for the repurchase of the stock of the subsidiary. The March 11, 2003 KCC order is filed as Exhibit 99(l) to this Annual Report on Form 10-K and incorporated herein by reference.
FERC Proceeding
On September 6, 2002, we filed an application with the Federal Energy Regulatory Commission (FERC) seeking authorization to issue unsecured long-term debt securities, on or before October 31, 2004, in an amount not to exceed $650 million at any one time. On February 20, 2003, FERC approved our request subject to certain conditions and also issued generic industry wide guidelines for future debt financings. On March 14, 2003, we informed FERC that we do not intend to issue any debt securities pursuant to the authority granted on February 20, 2003.
4. CHANGES IN ONEOK OWNERSHIP
On January 9, 2003, we announced that Westar Industries had entered into an agreement with ONEOK to sell ONEOK a portion of the shares of ONEOK Series A Convertible Preferred Stock held by Westar Industries at the prevailing market price, less transaction costs, and to exchange Westar Industries’ remaining shares of Series A Convertible Preferred Stock for new shares of ONEOK Series D Non-Cumulative Convertible Preferred Stock. On February 5, 2003, ONEOK repurchased from Westar Industries 9,038,755 shares of its Series A Convertible Preferred Stock, which were convertible into 18,077,511 shares of common stock. We received $300 million as a result of this sale.
Westar Industries also exchanged its remaining shares of Series A Convertible Preferred Stock for 21,815,386 new shares of ONEOK’s Series D Convertible Preferred Stock. ONEOK has agreed to file a shelf registration statement covering the Series D Convertible Preferred and common stock held by Westar Industries under the Securities Act of 1933. Future sales will be subject to conditions including the effectiveness of such registration, the required waiver or expiration of a 180-day lock-up period ending on July 22, 2003, and future market conditions. As of March 14, 2003, Westar Industries holds an approximate 27.5% ownership interest in ONEOK assuming conversion of the Series D Convertible Preferred Stock.
The Series D Convertible Preferred Stock has substantially the same terms as the Series A Convertible Preferred Stock, except that:
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The Series D Convertible Preferred Stock has a fixed quarterly cash dividend of 23.125 cents per share, as declared by ONEOK’s board of directors;
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The Series D Convertible Preferred Stock is transferable to a third party as convertible preferred stock;
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The Series D Convertible Preferred Stock is redeemable by ONEOK at any time after August 1, 2006 in the event that the closing price of ONEOK common stock exceeds $25 for 30 consecutive trading days after such date, at a per share redemption price of $20;
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Each share of Series D Convertible Preferred Stock is convertible into one share of ONEOK common stock, subject to adjustment for stock splits, stock dividends, reverse stock splits or any transaction with comparable effects; and
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Westar Industries may not convert any shares of Series D Convertible Preferred Stock held by it unless the annual per share dividend for the ONEOK common stock for the previous year is greater than 92.5 cents per share and such conversion would not subject us, Westar Industries nor ONEOK to the Public Utility Holding Company Act of 1935.
We, Westar Industries and ONEOK also agreed to amend the terms of the existing Shareholder Agreement (Shareholder Agreement) and Registration Rights Agreement. Under the new agreements:
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Westar Industries is prohibited from acquiring any additional securities of ONEOK.
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Westar Industries may make private sales of shares as long as each sale involves less than 5% of ONEOK’s outstanding common shares (assuming conversion of the Series D Convertible Preferred Stock to be sold) and is made to an owner of less than 5% of ONEOK’s outstanding common shares. Westar Industries may make public sales in any broad underwritten offering under the shelf registration statement to be filed by ONEOK within 60 days of the agreement, and has piggy-back registration rights.
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Westar Industries has the right to designate one ONEOK board member. Our designee will not have the right to sit on any committee of ONEOK’s board of directors. We have also agreed to vote in favor of the election of all candidates for director nominated by ONEOK’s board of directors.
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Westar Industries is not obligated to sell into stock repurchases by ONEOK.
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The new Shareholder Agreement will terminate if our or any affiliate’s beneficial ownership falls below 10% of ONEOK’s outstanding common shares (assuming conversion of the Series D Convertible Preferred into ONEOK common stock).
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The top-up rights, dilutive issuance rights and buy/sell option provided for in the previous Shareholder Agreement were eliminated in the new agreement.
In 2002 and prior periods, we accounted for our ONEOK common stock investment under the equity method of accounting. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and mark to market its fair value through other comprehensive income. We will begin accounting for our ONEOK Series D Convertible Preferred Stock investment under this method if and when a public market for these securities develops.
5. ACCOUNTS RECEIVABLE
Our accounts receivable on our consolidated balance sheets are comprised as follows:
On July 28, 2000, Westar Energy and KGE entered into an agreement under which we transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The agreement was amended on July 25, 2002 and is annually renewable upon agreement by all parties. The amendment to the agreement extended the term until July 23, 2003 and limited the amount of the accounts receivable we had a right to sell during certain periods to $125 million.
Under the terms of the agreement, Westar Energy and KGE may transfer accounts receivable to the bankruptcy-remote SPE, and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE’s receivables, including delinquency rates and debtor concentrations.
Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit, resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the conduit, which was $2.9 million for the year ended 2002, $5.4 million for the year ended 2001 and $3.7 million for the year ended 2000. These expenses are included in other income (expense) in our consolidated statements of income.
The outstanding balance of SPE receivables was $48.2 million at December 31, 2002 and $43.3 million at December 31, 2001, which is net of an undivided interest of $110.0 million and $100.0 million, respectively, in receivables sold by the SPE to the conduit. Our retained interest in the SPE’s receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit’s ownership interest in the SPE’s receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit and to absorb all credit losses incurred on any of the SPE’s receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets.
A termination event will be triggered under the terms of the agreement if Westar Energy’s credit rating ceases to be at least BB- by Standard & Poor’s Ratings Group (S&P) or if the issuer credit rating for Westar Energy ceases to be at least Ba3 by Moody’s Investors Service (Moody’s). If a termination event were to occur, the administrative agent would be required to give notice to us at least five business days prior to a termination of the facility. This notice provision allows for the administrative agent to waive the termination event by not giving notice or, in the event notice is given, allows us to repay the facility.
6. FINANCIAL INSTRUMENTS, ENERGY TRADING AND RISK MANAGEMENT
Values of Financial Instruments
The carrying values and estimated fair values of our financial instruments are as follows:
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 presented herein are based on information available at December 31, 2002 and 2001. These fair value estimates have not been comprehensively revalued for the purpose of these consolidated financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein.
Derivative Instruments and Hedge Accounting
Our operations are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect our 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, hedge a portion of these risks through the use of derivative financial instruments. We use the term 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 trading purposes.
We use derivative financial and physical instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, oil, coal and electricity and changes in interest rates. We also use derivative instruments for trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power and fossil fuel markets. Derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales are classified as energy trading contracts on our consolidated balance sheets. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.
Energy Trading 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 a variety of financial instruments, including forward contracts, options and swaps and trade energy commodity contracts daily. We also use hedging techniques to manage overall fuel expenditures. We procure physical product under fixed price agreements and spot market transactions.
Within the trading portfolio, we take certain positions to hedge a portion of physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. Changes in value are reflected in 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 trading activities.
We are involved in trading activities primarily to reduce risk from market fluctuations, capitalize on our market knowledge and enhance system reliability. 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 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 overall credit risk.
We are also exposed to commodity price changes outside of trading activities. We use derivatives 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 power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to changing market prices that may adversely impact our financial position and results of operations. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition. Due to the volatility of power market and gas prices, past prices cannot be used to predict future prices.
We use a mix of various fossil fuel types, including coal, natural gas and oil, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk associated with this commodity type. Due to the volatility of natural gas prices, we have begun to increasingly utilize our ability to switch to lower cost fuel types as the market allows.
Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically year to year based on the particular fuel’s availability, price, deliverability, unit outages and nuclear refueling. Our customers’ electricity usage could also vary dramatically 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 an open position, we are exposed to changing market prices that could have a material adverse impact on our 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.
Future changes in our creditworthiness and the creditworthiness of our counterparties may change the value of our portfolio. We adjust the value of contracts and set dollar limits with counterparties based on our assessment of their credit quality.
We use derivative financial instruments to reduce our exposure to certain fluctuations in some commodity prices, interest rates, and other market risks. When we enter into a financial instrument, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged, fluctuations in the value of the derivative instruments are generally offset by changes in the value or cash flows of the underlying exposures being hedged.
We record derivatives used for hedging commodity price risk in our consolidated balance sheets at fair value as energy trading contracts. The effective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is reported as a component of accumulated other comprehensive income (loss). This amount is reclassified into earnings in the period during which the hedged transaction affects earnings. Effectiveness is the degree to which gains and losses on the hedging instruments offset the gains and losses on the hedged item. The ineffective portion of the hedging relationship is recognized currently in earnings.
The fair values of derivatives used to hedge or modify our risks fluctuate over time. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions and the overall reduction in our risk relating to adverse fluctuations in interest rates, commodity prices and other market factors. In addition, the net income effect resulting from our derivative instruments is recorded in the same line item within our consolidated statements of income as the underlying exposure being hedged. We also formally assess, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposures. Any ineffective portion of a financial instrument’s change in fair value is immediately recognized in net income.
Hedging Activities
During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. Initially, we entered into futures and swap contracts with terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133.
In 2002, due to the increased availability of our coal units and because we began burning more oil as use of oil became more economically favorable than gas, we did not burn our forecasted amount of natural gas. In September 2002, we determined that we had over-hedged approximately 12,000,000 MMBtu for the remaining period of the hedge. As a result of the discontinuance of this portion of the cash flow hedge, we recognized a gain in earnings of $4.0 million. We are currently forecasting that we need a notional volume of 7,000,000 MMBtu for the remainder of the hedged period through July 2004.
Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on the term loan at 6.18%. In June 2002, we refinanced the term loan associated with this swap, which increased the effective rate of the swap to 6.43%. At December 31, 2002, the variable rate in effect for the term loan was 4.40%. Changes in the fair value of this cash flow hedge are due to fluctuations in the variable interest rate.
The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for the year ended December 31, 2002:
(a)
Natural gas hedge assets and liabilities are classified in the balance sheet as energy trading contracts. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the remaining 19 months that these relationships are in place.
(b)
The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions.
Fair Value of Energy Trading Contracts
The tables below show fair value of energy trading contracts outstanding for the year ended December 31, 2002, their sources and maturity periods:
These contracts were valued through market exchanges and, where necessary, broker quotes and industry publications. The sources of the fair values of the financial instruments related to these contracts are summarized in the following table:
(a)
The Black Option Pricing model is a variant of the Black-Scholes Option Pricing model.
Effects of Accounting Changes - Accounting for Energy Trading Contracts
In October 2002, the FASB, through the EITF, issued Issue No. 02-03, which rescinded Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, all new contracts that would otherwise have been accounted for under Issue No. 98-10 and that do not fall within the scope of SFAS No. 133 can no longer be marked-to-market and recorded in earnings as of October 25, 2002. We are not affected by this change in accounting principle and are not required to reclassify any of our contracts. EITF Issue No. 02-03 also requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. We began to classify our energy trading contracts on a net basis during the third quarter of 2002.
On July 1, 2002, we began reporting mark-to-market gains and losses on energy trading contracts on a net basis, whether realized or unrealized, in our consolidated income statements. Prior to July 1, 2002, we reported gains on these contracts in sales and losses in cost of sales in our consolidated income statements. The changes are reflected in our consolidated financial statements for the year ended December 31, 2002. Prior periods shown in our consolidated financial statements have been reclassified to reflect the effect of this change and to be comparable as required by GAAP. As a result of the net presentation, we expect significant reductions in our energy revenues and expenses from those reported in prior periods, which will not affect gross profit or net income. A summary of the effects of this change for the years ended December 31, 2002, 2001 and 2000 is as follows:
Changes to Income Statements
7. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
Depreciation expense on property, plant and equipment for the years ended December 31, 2002, 2001 and 2000 was as follows:
8. JOINT OWNERSHIP OF UTILITY PLANTS
Amounts and capacity presented above represent our share. Our share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in 1987, are included in operating expenses on our consolidated statements of income. Our share of other transactions associated with the plants is included in the appropriate classification in our consolidated financial statements.
9. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD
A portion of our investment in ONEOK is presently accounted for by the equity method. See Note 4 for a discussion of changes in our ownership in ONEOK and a change in the method by which we account for our investment.
The following is summarized unaudited ONEOK financial information related to our investment in ONEOK:
ONEOK earnings for 2001 include a pretax charge of $34.6 million for unrecovered gas costs from the winter of 2000-2001 and a $37.4 million pretax charge related to the Enron Corp. (Enron) bankruptcy. The charge for the outstanding gas costs is a result of the Oklahoma Corporation Commission order denying ONEOK the right to collect a portion of gas costs incurred during the winter of 2000-2001. Gas prices increased significantly in this period due to high demand and a perceived supply shortage. The charges related to Enron’s bankruptcy are due to Enron’s non-payment of both financial and physical natural gas positions for November and December of 2001.
During 2001, we disposed of 98% of our portfolio of affordable housing tax credit limited partnerships. The net impact of our total investment in these partnerships on our earnings, including equity in earnings, loss on disposal and generated tax credits was a benefit of $5.3 million.
During 2002, the net impact on our earnings from our remaining investments in affordable housing tax credit limited partnerships was an expense of $0.4 million.
10. MONITORED SERVICES’ CUSTOMER ACCOUNTS
The following is a rollforward of the investment in customer accounts (at cost) of the monitored services segment for the following years:
Accumulated amortization of the investment in customer accounts at December 31, 2002 was $678.9 million and $614.5 million at December 31, 2001. Customer account amortization expense was $83.3 million for 2002, $148.0 million for 2001, and $158.7 million for 2000.
During 2002, the monitored services segment had a net loss of 62,656 customers or a 5.3% decrease in its customer base from January 1, 2002.
11. SHORT-TERM DEBT
Certain banks provide us a revolving credit facility on a committed basis totaling $150 million. The facility is secured by KGE’s first mortgage bonds and matures on June 6, 2005, provided that if we have not refinanced or provided for the payment of our putable/callable notes due August 15, 2003, or our 6.875% senior unsecured notes due August 1, 2004, at least 60 days prior to either of the respective due dates, the maturity date is 60 days prior to
either of the respective due dates. As of December 31, 2002, borrowings on the revolving credit facility were $1.0 million, leaving $149 million remaining capacity under this facility. See Note 12 for a discussion of covenants applicable to our credit facilities.
We also had arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $7.0 million through December 31, 2002. These lines of credit were canceled on December 31, 2002.
Information regarding our short-term borrowings is as follows:
Our interest expense on short-term debt and other was $39.8 million in 2002, $40.6 million in 2001 and $63.1 million in 2000.
12. LONG-TERM DEBT
Outstanding Debt
Long-term debt outstanding is as follows at December 31:
The amount of Westar Energy’s first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of KGE’s first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion, unless amended. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions of each mortgage. As of December 31, 2002, $70.4 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage, except in connection with refundings. As of December 31, 2002, approximately $302.5 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
Protection One Europe has recognized as a financing transaction cash received through the sale of security equipment and future cash flows to be received under security equipment operating lease agreements with customers to a third-party financing company.
The indentures governing all of Protection One’s debt securities require that Protection One offer to repurchase the securities in certain circumstances following a change of control.
Debt Covenants
Our debt financing agreements require, among other restrictions, that we satisfy certain financial covenants. These debt instruments contain restrictions based on EBITDA. The definition of EBITDA varies among the various indentures. EBITDA is generally derived by adding to income (loss) before income taxes, the sum of interest expense and depreciation and amortization expense. However, under the varying definitions of the indentures, additional adjustments are required. A violation of these restrictions would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable. We are in compliance with these covenants. The most restrictive of these covenants in Westar Energy’s debt instruments are as follows:
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Consolidated Leverage Ratio: Consolidated total debt to earnings before interest, taxes, depreciation and amortization (EBITDA) for the most recent four consecutive quarters must be less than 6.00 to 1.00 at December 31, 2002 and 5.75 to 1.00 each quarter thereafter until June 2005. At December 31, 2002, our ratio was 5.13.
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Consolidated Interest Coverage Ratio: EBITDA to consolidated interest expense for the most recent four consecutive quarters must be greater than 2.00 to 1.00. At December 31, 2002, our ratio was 2.54.
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Consolidated Debt to Total Capital Ratio: Consolidated total debt to consolidated total capital for the most recent quarter must be less than 0.65 to 1.00. At December 31, 2002, our ratio was 0.618.
The indentures governing Protection One’s public indebtedness require it to satisfy certain financial covenants in order to borrow additional funds. At December 31, 2002, Protection One was in compliance with the covenants under its debt instruments. The most restrictive of these covenants in Protection One’s debt instruments are as follows:
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Total Debt to EBITDA Ratio: Total debt to annualized EBITDA for the most recent quarter must be less than 6.0 to 1.0. For the quarter ended December 31, 2002, the ratio was 4.0 to 1.0.
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EBITDA to Interest Expense Ratio: EBITDA to interest expense for the most recent quarter must be greater than 2.25 to 1.0. For the quarter ended December 31, 2002, the ratio was 3.1 to 1.0.
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Senior Debt to EBITDA Ratio: Senior debt to annualized EBITDA for the most recent quarter must be less than 4.0 to 1.0. For the quarter ended December 31, 2002, the ratio was 2.9 to 1.0.
The indentures contain other covenants that impose operational restrictions on Protection One that are not as burdensome to Protection One as those listed above, and none are based on credit ratings. A violation of the indenture covenants would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable.
Following a change of control of Protection One, its revolving credit facility provided by Westar Industries becomes due in full. The holders of Protection One’s senior subordinated discount notes and convertible notes have an optional redemption at approximately 101% of par and holders of Protection One’s senior notes and senior subordinated notes have an optional redemption at 101% of par, if a change in control is coupled with two ratings downgrades.
Maturities
Maturities of long-term debt as of December 31, 2002 are as follows:
Our interest expense on long-term debt was $229.5 million in 2002, $220.2 million in 2001 and $218.3 million in 2000.
13. DEBT FINANCINGS
On May 10, 2002, we completed offerings for $365 million of our first mortgage bonds and $400 million of our unsecured senior notes, both of which will be due on May 1, 2007. The first mortgage bonds bear interest at an annual rate of 7 7/8% and the unsecured senior notes bear interest at an annual rate of 9 3/4%. Interest on the first mortgage bonds and unsecured senior notes is payable semi-annually on May 1 and November 1 of each year. The net proceeds from these offerings were used to repay outstanding indebtedness of $547 million under our existing secured bank term loan, provide for the repayment of $100 million of our 7.25% first mortgage bonds due August 15, 2002 together with accrued interest, reduce the outstanding balance on our existing secured revolving credit facility and pay fees and expenses of the transactions. In conjunction with our May 10, 2002 financing, we amended our secured revolving credit facility to reduce the total commitment under the facility to $400 million from $500 million and to release $100 million of our first mortgage bonds from collateral.
On June 6, 2002, we entered into a secured credit agreement providing for a $585 million term loan and a $150 million revolving credit facility, each maturing on June 6, 2005, provided that if we have not refinanced or provided for the payment of our putable/callable notes due August 15, 2003, or our 6.875% senior unsecured notes due August 1, 2004, at least 60 days prior to either of the respective due dates, the maturity date is the date 60 days prior to either of the respective due dates. All loans under the credit agreement are secured by KGE’s first mortgage bonds. The proceeds of the term loan were used to retire an existing $400 million revolving credit facility with an outstanding principal balance of $380 million, to provide for the repayment at maturity of $135 million principal amount of KGE first mortgage bonds due December 15, 2003 together with accrued interest, to repurchase approximately $45 million of our outstanding unsecured notes and to pay customary fees and expenses of the transactions.
We will continue to report as outstanding debt on our consolidated balance sheet the $135 million principal amount of KGE first mortgage bonds due December 15, 2003, until the funds that have been irrevocably deposited with the trustee are used to retire such bonds at maturity. The cash deposited with the trustee is included in our
consolidated balance sheet as part of restricted cash and can only be used for the purpose of repaying this indebtedness and related interest.
14. CALL OPTION
In August 1998, we entered into a call option with an investment bank related to the issuance of $400 million of our putable/callable notes. This call option is required to be settled by August 2003 through either a cash payment or a remarketing or refinancing of the putable/callable notes. The ultimate value of the call option will be based on the difference between the 10-year United States treasury rate on August 12, 2003 and 5.44%. If the 10-year United States treasury rate on August 12, 2003 is less than 5.44%, we will have a liability to the investment bank at that time. At December 31, 2002, our potential liability under the call option was $62.2 million. Based on the 10-year forward treasury rate on March 14, 2003 of 3.91%, we would be obligated to make a cash payment of approximately $69.1 million to settle the call option if we did not remarket or refinance the notes. The amount of our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. If settled through a remarketing or refinancing, any liability related to the call option will be amortized as a credit to interest expense over the term of the new debt. The investment bank will price the notes to yield a market premium adequate to allow the investment bank to retain proceeds equal to the fair value of the call option at settlement.
At the time of issuance of the notes in 1998, we were not required by GAAP to account separately for the call option. However, when we began retiring these notes as a part of our overall debt reduction strategy, the portion of the call option associated with the retired notes became a free-standing option required to be treated as a derivative instrument under SFAS No. 133. In addition, under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our balance sheet reflects the current fair value of the free standing portion of the call option. For 2002, we recognized a loss of $10.1 million, net of $6.7 million tax benefit, related to the fair value of the call option associated with the putable/callable notes at the time the notes were retired. This loss is included in our consolidated statements of income as part of the gain on extinguishment of debt line item of other income. For 2002, we also recorded an additional non-cash charge of $13.6 million, net of $9.0 million tax benefit, to reflect mark to market changes in the fair value of the call option associated with the retired notes. This charge is reflected in the other line item of other income in our consolidated statements of income. In total, the loss recorded related to the fair value of the call option for the year ended December 31, 2002 was $23.7 million, net of $15.7 million tax benefit.
15. EMPLOYEE BENEFIT PLANS
Pension
We maintain qualified noncontributory defined benefit pension plans covering substantially all utility employees. Pension benefits are based on years of service and the employee’s compensation during the five highest paid consecutive years out of ten before retirement. Our policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain officers.
Post-retirement Benefits
We accrue the cost of post-retirement benefits, primarily medical benefit costs, during the years an employee provides service.
The following tables summarize the status of our pension and other post-retirement benefit plans:
In selecting an assumed discount rate, fixed income security yield rates for 30-year Treasury bonds and corporate high-grade bond yields are considered. The assumed rate of return on plan assets is based on long-term returns forecast for the type of investments held by the plan.
Pension plan assets are primarily made up of equity and fixed income investments. The market value of the plan assets has been affected by declines in equity markets. At December 31, 2002, the fair value of pension plan assets was $382.3 million. Actual return on plan assets declined by approximately $2.1 million during 2001 and by
approximately $58.5 million during 2002. Absent a substantial recovery in the equity markets, pension costs, cash funding requirements and the additional pension liability could substantially increase in future years.
For measurement purposes, an annual health care cost growth rate of 10% was assumed for 2002, decreasing by 1% per year to 5% in 2007 and thereafter. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $2.2 million and the aggregate of the service and interest cost components by $0.2 million. A 1% decrease in the trend rate would decrease the present value of the accumulated projected benefit obligation by $2.2 million and the aggregate of the service and interest cost components by $0.2 million.
Savings Plans
We maintain savings plans in which substantially all employees participate, with the exception of Protection One and Protection One Europe employees. We match employees’ contributions up to specified maximum limits. Our contributions to the plans are deposited with a trustee and are invested in one or more funds, including the company stock fund at the direction of plan participants. Our contributions were $3.8 million for 2002, $4.4 million for 2001 and $3.9 million for 2000.
Under our qualified employee stock purchase plan established in 1999, full-time, non-union employees may purchase designated shares of our common stock at no more than a 15% discounted price. Our employees purchased 46,431 shares in 2002 at an average price of $8.43 per share. Employees purchased 67,519 shares at an average price of $14.56 per share in 2001 and employees purchased 249,050 shares at an average price of $14.00 per share in 2000. A total of 1,250,000 shares of common stock have been reserved for issuance under this program.
Protection One also maintains a savings plan. Contributions are allocated among participants based upon the respective contributions made by the participants through salary reductions during the year. Protection One’s matching contributions may be made in Protection One common stock, in cash or in a combination of both stock and cash. Protection One’s matching cash contribution to the plan was approximately $1.1 million for 2002, $1.1 million for 2001 and $0.7 million for 2000.
Protection One maintains a qualified employee stock purchase plan that allows eligible employees to acquire shares of Protection One common stock at no more than a 15% discounted price. Employees purchased 151,244 shares in 2002 at an average price of $1.69 per share. Employees purchased 489,791 shares at an average price of $0.77 per share in 2001 and 145,523 shares at an average price of $0.69 per share in 2000. A total of 1,650,000 shares of common stock have been reserved for issuance under this program.
Stock Based Compensation Plans
We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which utility employees are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and board members (plan participants). Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, restricted shares, RSUs, performance shares and performance share units to plan participants. Up to five million shares of common stock may be granted under the LTISA Plan. Dividend equivalents accrue on the awarded RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on our common stock.
During 2002, 584,165 RSUs were granted to a broad-based group of over 800 non-union employees. Each RSU represents a right to receive one share of our common stock at the end of the restricted period assuming performance criteria are met. In addition, RSUs linked to 783,400 shares of Protection One common stock and 12,193 shares of Guardian International, Inc. preferred stock held by us were granted to certain officers. During 2001, 579,915 RSUs were granted. Also in 2000, non-union employees were offered the opportunity to exchange their stock options for RSUs of approximately equal economic value. As a result, 2,246,865 stock options were canceled in 2000 in exchange for 614,741 RSUs. The grant of RSUs is shown as a separate component of shareholders’ equity. Unearned compensation is being amortized to expense over the vesting period. This compensation expense is shown as a separate component of shareholders’ equity.
During the second quarter of 2002, active employees awarded RSUs in prior years were allowed to exchange eligible RSUs for shares of common stock. As a result, approximately 145,000 RSUs were exchanged for approximately 105,000 shares of our common stock. In addition, approximately 317,000 RSUs held by certain executive officers were exchanged for approximately 12,500 shares of Guardian International, Inc. preferred stock held by us. Compensation expense associated with this exchange totaled approximately $9.0 million for 2002. Also, in September 2002, former employees had the opportunity to convert vested RSUs into common stock. As a result, 34,433 shares of our common stock were issued in exchange for 68,865 RSUs.
Another component of the LTISA Plan is the Executive Stock for Compensation program, where in the past eligible employees were entitled to receive RSUs in lieu of current cash compensation. The Executive Stock for Compensation program was modified in 2001 to pay a portion of current compensation in the form of stock. Although this plan was discontinued, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. At the end of the deferral period, RSUs are paid in the form of stock. In 2002, plan participants were awarded 12,121 shares of common stock for dividends. In 2001, eligible employees were awarded 31,881 shares of common stock representing $0.7 million of compensation. In 2000, 95,000 RSUs were awarded in lieu of $1.3 million in cash compensation. Participants received common stock distributions of 40,097 shares in 2002 and 974 shares in 2001 and 2,978 shares in 2000.
Stock options under the LTISA plan are as follows:
Stock options issued and outstanding at December 31, 2002 are as follows:
RSUs under the LTISA plan are as follows:
RSUs issued and outstanding at December 31, 2002 are as follows:
An equal number of dividend equivalents was issued to recipients of stock options and RSUs. Recipients of RSUs receive dividend equivalents when dividends are paid on shares of company stock. The value of each dividend equivalent related to stock options is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend equivalents, with respect to stock options, expire after nine years from date of grant. The weighted-average fair value at the grant-date of the dividend equivalents on stock options was $6.35 in 2002 and $6.28 in 2001.
The fair value of stock options and dividend equivalents were estimated on the date of grant using the Black-Scholes Option Pricing model. The model assumed the following at December 31, 2000. There were no options granted in 2002 or 2001.
Protection One Stock Warrants and Options
Protection One has outstanding stock warrants and options that were considered reissued and exercisable upon our acquisition of Protection One on November 24, 1997. The 1997 Long-Term Incentive Plan (the LTIP), approved by the Protection One stockholders on November 24, 1997, provides for the award of incentive stock options to directors, officers and key employees. Under the LTIP, 4.2 million shares of Protection One are reserved for issuance, subject to such adjustment as may be necessary to reflect changes in the number or kinds of shares of common stock or other securities of Protection One. The LTIP provides for the granting of options that qualify as incentive stock options under the Internal Revenue Code and options that do not so qualify.
Options issued since 1997 have a term of 10 years and vest ratably over 3 years. The purchase price of the shares issuable pursuant to the options is equal to (or greater than) the fair market value of the common stock at the date of the option grant.
A summary of warrant and option activity for Protection One common stock from December 31, 2000 through December 31, 2002 is as follows:
Stock options and warrants of Protection One issued and outstanding at December 31, 2002 is as follows:
On April 16, 2001, Protection One granted an option to purchase an aggregate of 875,000 shares of its common stock to its chief executive officer as part of his employment agreement with Protection One. The option has a term of ten years and vests ratably over three years. The purchase price of the shares issuable pursuant to the option is $1.32 per share while the fair market value of the common stock at the date of the option grant was $1.79 per share resulting in $0.4 million in deferred compensation expense amortized over three years. The expense amounts were $0.1 million and $0.1 million, respectively, for 2002 and 2001.
The weighted average fair value of options for Protection One stock granted by Protection One estimated on the date of grant was $1.95 during 2002, $0.98 during 2001 and $1.13 during 2000. The fair value was calculated using the following assumptions:
On April 16, 2001, Protection One granted an option to purchase an aggregate of 250,000 shares of its common stock to Guardian International, Inc. (Guardian), in connection with the hiring of Protection One’s chief executive officer, who was formerly the chief executive officer of Guardian. The option has a term of ten years and vests ratably over three years. The purchase price of the shares issuable pursuant to the option is $1.32 per share while the fair market value of the common stock at the date of the option grant was $1.79 per share resulting in $0.4 million expense in 2001. On December 31, 2001, all shares were outstanding and none were exercisable. On December 31, 2002, all shares were outstanding and 83,334 shares are exercisable. The shares issued to Guardian are not included in the outstanding options listed in the above tables.
Split Dollar Life Insurance Program
In 1998, we established a split dollar life insurance program for our benefit and the benefit of certain of our executive officers. Under the program, we purchased life insurance policies, which provide the beneficiary a death benefit in an amount equal to the face amount of the policy reduced by the greater of (i) all premiums paid by the company or (ii) the cash surrender value of the policy, which amount, at the death of the executive, will be returned to us. We retain an equity interest in the death benefit and cash surrender value of the policy to secure this repayment obligation.
Subject to certain conditions, executive officers may transfer to us their interest in the death benefit based on a predetermined formula. The liability associated with this program was $12.0 million as of December 31, 2002 and $18.6 million as of December 31, 2001. The obligations under this program can increase and decrease based on our total return to shareholders and payments to plan participants. This liability decreased approximately
$6.6 million in 2002 due to payments to plan participants, $0.5 million in 2001 due to balance adjustments, and $12.8 million in 2000 due primarily to payments to plan participants.
16. INCOME TAXES
Income tax expense (benefit) is composed of the following components at December 31:
Temporary differences related to deferred tax assets and deferred tax liabilities are summarized in the following table.
Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows:
In accordance with various rate orders, we have not yet collected through rates certain accelerated tax deductions, which have been passed on to customers. We believe it is probable that the net future increases in income taxes payable will be recovered from customers. We have recorded a regulatory asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. This liability is classified above as deferred 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:
17. COMMITMENTS AND CONTINGENCIES
City of Wichita Franchise
KGE’s franchise with the City of Wichita to provide retail electric service is effective through December 1, 2003. We are currently negotiating with the City of Wichita for a long-term franchise agreement. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise. Customers within the Wichita metropolitan area account for approximately 21% of our total energy sales volumes.
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 $153.1 million at December 31, 2002, of which $32.2 million has been committed. The $32.2 million commitment relates to purchase obligations issued and outstanding at year-end, as well as a contract tariff for telecommunication services.
The aggregate amount of required payments at December 31, 2002 is as follows:
Clean Air Act
We must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. Material capital expenditures have not been required to meet Phase II sulfur dioxide and nitrogen oxide requirements. We may purchase SO2 allowances as necessary to meet these requirements.
Manufactured Gas Sites
We have been associated with 15 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 (KDHE) entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow us to investigate these sites and set remediation priorities based on the results of the investigations and risk analysis. At December 31, 2002, the costs incurred for preliminary site investigation and risk assessment have been minimal. In accordance with the terms of the strategic alliance with ONEOK, ownership of twelve of these sites and the responsibility for clean up of these sites were transferred to ONEOK. The ONEOK agreement limits our future liability associated with these sites to an immaterial amount. Our investment earnings from ONEOK could be impacted by these costs.
EPA New Source Review
The Environmental Protection Agency (EPA) is conducting an enforcement initiative at a number of coal-fired power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA has requested information from us under Section 114(a) of the Clean Air Act (Section 114). A Section 114 information request requires us to provide responses to specific EPA questions regarding certain projects and maintenance activities that the EPA believes may have violated the New Source Performance Standard and New Source Review requirements of the Clean Air Act. The EPA contends that power plants are required to update emission controls at the time of major maintenance or capital activity. We believe that maintenance and capital activities performed at our power plants are generally routine in nature and are typical for the industry. We are complying with this information request, but cannot predict the outcome of this investigation at this time. Should the EPA determine to take action, the resulting additional costs to comply could be material. We would expect to seek recovery through rates of any settlement amounts.
The EPA has initiated civil enforcement actions against other unaffiliated utilities as part of its initiative. Settlement agreements entered into in connection with some of these actions have provided for expenditures to be made over extended time periods.
Solid Waste Landfills
We have operating solid waste landfills at Jeffrey Energy Center, Tecumseh Energy Center and Lawrence Energy Center (LEC) for the single purpose of disposing of coal combustion waste material. Additionally, there is one retired landfill at both LEC and Neosho Energy Center. All landfills are permitted by the KDHE and meet all applicable requirements. The operating landfill at LEC is projected to be full by 2007 requiring us to permit and
construct a new landfill at this site. It is anticipated that the lead time for permitting a new landfill may be significant, which will require this activity to begin in 2003.
Superfund Sites
In December 1999, we were identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). Based upon previous experience and the limited nature of our business transactions with the previous owners of the site, our obligation, if any, at the Kansas City site is not expected to have a material impact on our financial position or results of operations.
Nuclear Decommissioning
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 decommissioning. These plans are designed so that funds required for decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.
We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.
The KCC reviews our decommissioning fund financial plans in two phases. Phase one is the approval of the decommissioning study, the current year dollar amount and the future year dollar amount. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing its plans of how to fund the future year dollar amount for the pro rata share of the plant.
On February 25, 2002, we filed an application with the KCC to modify the funding schedule to reflect an assumed life of Wolf Creek through 2045 (see Note 3). This modification was granted on March 8, 2002. The filing reflects the current estimate in 1999 dollars of $221 million, but a future estimate in 2045 through 2054 of $1.28 billion. An updated decommissioning and dismantlement cost estimate was filed with the KCC on August 30, 2002. Costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied upon the site-specific, technical information developed in 1999, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. We anticipate a KCC order on the August 2002 decommissioning study in the second quarter of 2003. The actual decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.
We will file a funding schedule to reflect the KCC’s order on the August 2002 decommissioning study by the end of the second quarter of 2003 and anticipate a KCC order on the funding schedule in the third quarter of 2003.
Decommissioning costs are currently being charged to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the March 8, 2002 funding schedule. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek as determined by the KCC through 2045. The Nuclear Regulatory Commission (NRC) requires that funds to meet its decommissioning funding assurance requirement be in our 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.
Amounts expensed approximated $3.85 million in 2002 and will remain unchanged through 2044, subject to the August 2002 decommissioning cost review and revised funding schedule to be filed in the second quarter of 2003. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.56%.
Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $63.5 million at December 31, 2002 and $66.6 million at December 31, 2001. The balance in the trust fund decreased from 2001 to 2002 due to the decline in the market value of equity securities held in the trust. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.
Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized and depreciated over the appropriate period as part of the cost of the related tangible long-lived assets. The adoption of SFAS No. 143 will not impact income. Any income effects are offset by a regulatory asset created pursuant to SFAS No. 71. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
We adopted SFAS No. 143 on January 1, 2003, which required us to recognize and estimate 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. These amounts were estimated based on the calculation guidelines of SFAS No. 143. 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.
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. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation produced for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales.
A permanent disposal site will not be available for the nuclear industry until 2010 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 2016. 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.
On February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site in Nevada 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. In July 2002, the President signed a resolution approving the Yucca Mountain site after receiving the approval of this site from the U.S. Senate and House of Representatives. This action allows the DOE to apply to the NRC to license the project. The DOE expects that this facility will open in 2010. However, the opening of the Yucca Mountain site could be delayed 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. Terrorist acts are not excluded from the property and accidental outage policies, but are covered as a common occurrence under the Non-Terrorism Risk Insurance Act. The term common occurrence means that if terrorist acts occur against one or more commercial nuclear power plants insured by our insurance company within a 12-month period, all of these terrorist acts will be treated as one event and the owners of the plants will share one full limit of each type of policy, which is currently $3.24 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), our insurance provider. Currently there is $1 billion of reinsurance
purchased by NEIL. Claims that arise from terrorist acts are also covered by our nuclear liability and worker radiation policies. These policies are subject to one industry aggregate limit for such acts, currently $300 million for the risk of terrorism. Unlike the property and accidental outage policies, an industry-wide retrospective assessment program (discussed below) applies once the nuclear liability and worker radiation policies 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 $9.5 billion. This limit of liability consists of the maximum available commercial insurance of $300 million, and the remaining $9.2 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $88.1 million per incident at any commercial reactor in the country, payable at no more than $10 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, the U.S. Congress could impose additional revenue-raising measures to pay claims. If the $9.5 billion liability limitation is insufficient, the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims.
The Price-Anderson Act expired in August 2002. In late 2002, a renewal act was approved by Congress to be part of an energy bill to extend the Act for 15 years from August 1, 2002. The renewal act would have increased the annual retrospective premium limit from $10 million to $15 million per reactor per incident and increased the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident. Although the renewal act was approved by Congress, the energy bill was never signed by the President. However, in February 2003, the Act was extended to December 31, 2003 with no changes except for its expiration date. We expect that the Act will be renewed, but we are unable to predict whether the Act will be modified as proposed in 2002.
Nuclear Property Insurance
The owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.75 billion ($1.3 billion our share). 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 decommissioning the plant, toward a shortfall in the 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 $24.5 million ($11.5 million our share).
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 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, 2002, our share of WCNOC’s nuclear fuel commitments were approximately $5.0 million for uranium concentrates expiring in 2003, $0.6 million for conversion expiring in 2003, $21.5 million for enrichment expiring at various times through 2006 and $57.5 million for fabrication through 2025.
At December 31, 2002, our coal and coal transportation contract commitments in 2002 dollars under the remaining terms of the contracts were approximately $2.0 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013.
At December 31, 2002, our natural gas transportation commitments in 2002 dollars under the remaining terms of the contracts were approximately $56.2 million. The natural gas transportation contracts provide firm service to several of our gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016.
Energy Act
As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. Our portion of the assessment for Wolf Creek is approximately $8.1 million. To date, we have paid approximately $6.8 million, with the remainder payable over the next four years. Such costs are recovered through the ratemaking process.
18. LEGAL PROCEEDINGS
We, Westar Industries, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Monitoring) and certain present and former officers and directors of Protection One were defendants in a purported class action litigation in the U.S. District Court for the Central District of California, “Alec Garbini, et al v. Protection One, Inc., et al,” No. CV 99-3755 DT (RCx). On August 20, 2002, the parties filed a Stipulation of Settlement which provided for, among other things, no finding of wrongdoing on the part of any of the defendants, or any other finding that the claims alleged had merit, and a $7.5 million payment to the plaintiffs, which has been fully funded by Protection One’s existing insurance. On November 4, 2002, the district court approved the settlement and entered an Order and Final Judgment. The court certified a class for settlement purposes consisting of all persons and entities who purchased or otherwise acquired the common stock of Protection One during the time period beginning and including February 10, 1998 through February 2, 2001. The Order and Final Judgment provides for, among other things, dismissal with prejudice and release of all Class members’ claims against us, Westar Industries, Protection One, Monitoring, and the present and former officers and directors of Protection One.
We and the Public Service Company of New Mexico settled the litigation between us on September 24, 2002. Each side agreed to release all of its claims and potential claims in connection with the transaction.
We and certain of our present and former officers are defendants in five purported class action lawsuits filed during January and February 2003 in U.S. District Court in Topeka, Kansas. All of the lawsuits allege securities law violations resulting from power marketing transactions with Cleco Corporation (Cleco) and the first and second quarter 2002 restatements related to the revised goodwill impairment charge and the mark to market charge on our putable/callable notes. We intend to vigorously defend against these actions. We are unable to predict the ultimate impact of this matter on our financial position, results of operations and cash flows.
We and certain of our present and former officers are defendants in purported class action lawsuits filed during March 2003 in U.S. District Court in Topeka, Kansas on behalf of participants in and beneficiaries of our Employees’ 401(k) Savings Plan. All of the lawsuits allege violations of the Employee Retirement Income Security Act arising from the conduct of certain present and former officers who served or are serving as fiduciaries for the plan. The conduct is related to the matters alleged as a basis for securities law violations in the class action lawsuits disclosed in the preceding paragraph. We intend to vigorously defend against these actions. We are unable to predict the ultimate impact of this matter on our financial position, results of operations and cash flows.
We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations.
See also Notes 3, 19 and 35 for discussion of KCC regulatory proceedings and a FERC proceeding, an investigation by the United States Attorney’s Office, an inquiry by the Securities and Exchange Commission (SEC), an investigation by FERC of certain of our power transactions and potential liabilities to David C. Wittig and Douglas T. Lake.
19. ONGOING INVESTIGATIONS
Grand Jury Subpoena
On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and the company in general. We are providing information in response to these requests and are fully cooperating in the investigation. We have not been informed that we are a target of the investigation. We are unable to predict the ultimate outcome of the investigation or its impact on us.
Securities and Exchange Commission Inquiry
On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these matters and other matters within the scope of the grand jury investigation. We are unable to predict the ultimate outcome of the inquiry or its impact on us.
Special Committee Investigation
Our board of directors appointed a Special Committee of directors to investigate management matters and matters that are the subject of the grand jury investigation and SEC inquiry. The Special Committee retained counsel and other advisors. The Special Committee investigation has been completed and has not resulted in adjustments to our consolidated financial statements.
FERC Subpoena
On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco 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.
Cleco publicly disclosed in November 2002 that Cleco and its affiliates had engaged in certain trades that may have violated FERC affiliate transaction rules applicable to Cleco. The affiliate transactions involved power sales from one Cleco affiliate to Westar Energy and then back to another or the same Cleco affiliate. The transactions totaled approximately $3.8 million in 2002, $12.6 million in 2001 and $3.4 million in 2000. The total amount of these transactions represented less than 1% of our total revenues in 2002, 2001 and 2000.
Among the issues being reviewed by FERC are transactions we conducted with third parties to facilitate power transfers between our system and our marketing operations. These transactions and other power marketing and trading activities were recently reviewed in a KCC ordered audit of our power marketing operations. This review was conducted by an independent third party with industry experience who was approved by the KCC. The review found no irregularities in the structure or pricing of the transactions.
We have provided information to FERC in response to the subpoena. We believe that our participation in these transactions did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation.
20. COMMON STOCK, PREFERRED STOCK AND OTHER MANDATORILY REDEEMABLE SECURITIES
Our Restated Articles of Incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2002, 72,840,217 shares were issued and 71,506,953 shares were outstanding.
We have a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP may be either original issue shares or shares purchased in the open market. During 2002, a total of 7,087,125 shares were purchased from the company through the issuance of 6,936,289 original issue shares and 150,836 through the reissuance of treasury shares. Of the total shares purchased from us in 2002, 5,253,502 were acquired by Westar Industries and the balance of the shares were for the DSPP, ESPP, 401(k) match and other stock based plans operated under the 1996 Long-Term Incentive and Share Award Plan. At December 31, 2002, 1,855,808 shares were available under the DSPP registration statement.
The November 8, 2002 KCC order directed us to reverse all transactions in 2002 recorded as equity investments by us in Westar Industries. In compliance with that order, on December 9, 2002, Westar Industries transferred to us 20,301,489 shares of our common stock that had been previously issued to Westar Industries.
Treasury Stock
At December 31, 2002, we had a treasury stock balance of 1,333,264 shares. Westar Industries did not own any of our common stock and Protection One owned 850,000 shares of our common stock. At December 31, 2001, all of our treasury stock was owned by Westar Industries, except for 50,000 shares owned by Protection One.
See Note 34 for information regarding our purchase during the first quarter of 2003 of shares of our common stock held by Protection One.
Preferred Stock Not Subject to Mandatory Redemption
Westar Energy’s cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at our option.
The provisions of Westar Energy’s Restated Articles of Incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. If the ratio of the capital represented by our preferred stock and common stock (together, Subordinated Stock) (including premiums on capital stock) and its surplus accounts, to its total capital and its surplus accounts at the end of the second month immediately preceding the date of the proposed payment, adjusted to reflect the proposed payment (Capitalization Ratio), will be less than 20%, then the payment of the dividends on Subordinated Stock shall not exceed 50% of net income available for dividends for the 12-month period ending with and including the date of the proposed payment. If the Capitalization Ratio is 20% or more but less than 25%, then the payment of dividends on the Subordinated Stock, including the proposed payment, then the payments shall not exceed 75% of its net income available for dividends for such 12-month period. Except to the extent permitted above, no payment or other distribution may be made that would reduce the Capitalization Ratio to less than 25%. At December 31, 2002, the capitalization ratio was greater than 25%.
So long as there are any outstanding shares of Westar Energy preferred stock, Westar Energy shall not without the consent of a majority of the shares of preferred stock or if more than one-third of the outstanding shares of preferred stock vote negatively and without the consent of a percentage of any and all classes required by law and Westar Energy’s Articles of Incorporation, declare or pay any dividends (other than stock dividends or dividends applied by the recipient to the purchase of additional shares) or make any other distribution upon Subordinated Stock unless, immediately after such distribution or payment the sum of Westar Energy’s capital represented by the outstanding Subordinated Stock and our earned and any capital surplus shall not be less than $10.5 million plus an amount equal to twice the annual dividend requirement on all the then outstanding shares of preferred stock.
Other Mandatorily Redeemable Securities
On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued $100 million of 7 7/8% Cumulative Quarterly Income Preferred Securities, Series A, of which $98.8 million were outstanding at December 31, 2002. The securities are redeemable at the option of Western Resources Capital I on or after December 11, 2000, at $25 per security plus accrued interest and unpaid dividends. Holders of the securities are entitled to receive distributions at an annual rate of 7 7/8% of the liquidation value of $25. Distributions are payable quarterly and are tax deductible by us. These distributions are recorded as interest expense. The sole asset of the trust is $103 million principal amount of Westar Energy 7 7/8% Deferrable Interest Subordinated Debentures, Series A due December 11, 2025.
On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120 million of 8 1/2% Cumulative Quarterly Income Preferred Securities, Series B, of which $115.7 million were outstanding at December 31, 2002. The securities are redeemable at the option of Western Resources Capital II, on or after July 31, 2001, at $25 per preferred security plus accumulated and unpaid distributions. Holders of the securities are entitled to receive distributions at an annual rate of 8 1/2% of the liquidation value of $25. Distributions are payable quarterly and are tax deductible by us. These distributions are recorded as interest expense. The sole asset of the trust is $124 million principal amount of Westar Energy 8 1/2% Deferrable Interest Subordinated Debentures, Series B due July 31, 2036.
In addition to Westar Energy’s obligations under the Subordinated Debentures discussed above, Westar Energy has guaranteed, on a subordinated basis, payment of distributions on the preferred securities. These undertakings constitute a full and unconditional guarantee by Westar Energy of the trust’s obligations under the preferred securities.
21. MARKETABLE SECURITIES
During the last three years, we sold substantially all of our investments in marketable securities. These securities were classified as available-for-sale. Realized gains and losses are included in earnings and were derived using the specific identification method. The following table summarizes our marketable security sales for the years ended December 31, 2002, 2001 and 2000:
In February 2000, one of the paging companies we held an interest in made an announcement that significantly increased the market value of paging company securities in general. During the first quarter of 2000, we sold the remainder of these securities for a gain of $24.9 million.
During 2001, we wrote down the cost basis of certain securities to their estimated fair value. The fair value of these equity securities had declined below our cost basis, and we determined that the decline was other than temporary. The amount of the write down totaled $11.1 million, of which $9.6 million related to an investment. The write down is included in other income (expense).
See Note 4 for information regarding the classification of our ONEOK investment.
22. MONITORED SERVICES DISPOSITIONS
In 2001, Protection One and Protection One Europe disposed of certain monitored security operations for approximately $48.0 million and we recorded a pre-tax loss of $13.1 million.
23. IMPAIRMENT CHARGES
Effective January 1, 2002, we adopted SFAS No. 142 and SFAS No. 144. SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. The completion of the impairment tests, based upon a valuation performed by an independent appraisal firm, as of January 1, 2002, indicated that the carrying values of goodwill at Protection One and Protection One Europe had been impaired and impairment charges were recorded as discussed below.
Another impairment test of Protection One’s goodwill and customer accounts was completed as of July 1, 2002 (the date selected for Protection One’s annual impairment test), with the independent appraisal firm providing the valuation of the estimated fair value of Protection One’s reporting units, and no impairment was indicated. Protection One’s stock price declined after regulatory orders were issued (see Note 3), including the KCC’s December 23, 2002, order. As a result, Protection One retained the independent appraisal firm to perform an additional valuation of Protection One’s reporting units so it could perform an impairment test as of December 31, 2002, which resulted in the additional impairment charge discussed below.
SFAS No. 144 established a new approach to determining whether our customer account asset is impaired. The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of the reporting unit, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then we are required to mark the customer account asset down to fair value, by recording an impairment, to the extent fair value is less than our book value. To the extent net book value is less than fair value, no impairment would be recorded.
The new rule substantially reduces the net undiscounted cash flows for customer account impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16 year remaining life of the goodwill to the nine year remaining life of customer accounts for impairment evaluation purposes. Using these new guidelines, we determined that there was an indication of impairment of the carrying value of the customer accounts and an impairment charge was recorded as discussed below.
To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, we recorded a charge in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.
The impairment charge for goodwill recorded in the first quarter of 2002 is reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts is reflected in our consolidated statement of income as an operating expense. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002.
Protection One completed an additional impairment test of goodwill as of December 31, 2002. We recorded an impairment charge of $79.7 million, net of tax benefit and minority interests, in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill of Protection One’s North America segment, which is reflected in our consolidated statement of income as an operating expense.
We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill of Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe, which is reflected in our consolidated statement of income as an operating expense. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.
These charges for the year ended December 31, 2002, are detailed as follows:
We no longer amortize goodwill to expense because of the adoption of SFAS No. 142. The following table shows our results for the year ended December 31, 2002, compared to our results for the year ended December 31, 2001, calculated using the new accounting standard for goodwill, adjusted for minority interest.
The investment at cost in customer accounts at December 31, 2002 was $1.1 billion and at December 31, 2001 was approximately $1.4 billion. Accumulated amortization of the investment in customer accounts at December 31, 2002 was $678.9 million and at December 31, 2001 was $614.5 million. We recorded approximately $83.3 million of customer account amortization expense during the year ended December 31, 2002, $148.0 million during the same period of 2001 and $158.7 million during the year ended December 31, 2000. Customer account amortization expense is reduced primarily as a result of the impairment charge that reduced our customer account balance. The table below reflects the estimated aggregate customer account amortization expense for 2003 and each of the four succeeding fiscal years.
We are required to perform impairment tests for long-lived assets prospectively for our monitored services segment as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested upon certain triggering events, which include recurring operating losses, adverse business conditions, adverse regulatory rulings, declines in market values and other matters that negatively impact value. Given the potentially negative implications from the KCC’s December 23, 2002 order, and the subsequent decline in Protection One’s stock price, Protection One tested its goodwill for impairment at December 31, 2002, which resulted in the additional impairment charge discussed above. If future impairment tests for either goodwill or customer accounts indicate fair value is less than book value, we will be required to recognize additional impairment charges on these assets in the future. Any such impairment charges could be material.
24. CHANGE IN ESTIMATE OF CUSTOMER LIFE
During the first quarter of 2002, Protection One evaluated the estimated life and amortization rates for customer accounts, based on the results of a lifing study performed by a third party appraisal firm in the first quarter of 2002. The report showed Protection One’s North America customer pool can expect a declining revenue stream over the next 30 years with an estimated average remaining life of 9 years. Protection One’s Multifamily pool can expect a declining revenue stream over the next 30 years with an estimated average remaining life of 10 years. Taking into account the results of the lifing study and the inherent expected declining revenue streams for its North America and Multifamily customer pools, in particular the first five years, Protection One adjusted the rate of amortization on customer accounts for its North America and Multifamily customer pools to better match the rate and period of amortization expense with the expected decline in revenues. In the first quarter of 2002, Protection One changed its amortization rate for its North America pool to a 10-year 135% declining balance method from a 10-year 130% declining balance method. For the Multifamily pool, Protection One will continue to amortize on a straight-line basis utilizing a shorter nine year life. Protection One accounted for these amortization changes prospectively beginning January 1, 2002, as a change in estimate. These changes in estimates increased amortization expense for the year ended December 31, 2002 by approximately $0.8 million, net of $0.5 million tax.
25. LEASES
Operating Leases
The company leases office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates from 1 to 16 years. Rental payments for operating leases and estimated rental commitments are as follows:
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 operation 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.
Capital Leases
Assets recorded under capital leases are listed below:
Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases as of December 31, 2002 are listed below. Some capital leases are subject to covenants, which require us to maintain certain credit ratings.
26. GAIN ON DEBT RETIREMENTS
Protection One’s and our debt securities were repurchased in the open market and gains were recognized on the retirement of these debt securities. Prior to July 1, 2002, these were recognized as extraordinary gains.
Effective July 1, 2002, we adopted SFAS No. 145. This standard limits the income statement classification of gains and losses from extinguishment of debt as extraordinary to those transactions meeting the criteria of APB Opinion No. 30, “Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” SFAS No. 145 prohibits treating gains and losses associated with extinguishments resulting from a company’s risk management strategy as extraordinary. Under SFAS No. 145, current gains and losses from the extinguishment of debt are reported as other income. Gains or losses in prior periods that were previously classified as extraordinary that do not meet the APB Opinion No. 30 criteria have been reclassified to other income. The adoption of this standard did not impact our net income or financial condition.
27. DISCONTINUED OPERATIONS
During the second quarter of 2002, Protection One entered into negotiations for the sale of its Canadian business, which was included in our monitored services segment. The sale was consummated on July 9, 2002. Protection One recorded an impairment loss of approximately $1.3 million, net of $0.7 million tax benefit, in the second quarter of 2002 as a result of the sale.
The net operating losses of these operations are included in the consolidated statements of income under discontinued operations. The net operating loss for the year ended December 31, 2002, of $1.6 million, includes an impairment loss on customer accounts of approximately $1.9 million. An impairment charge of $2.3 million relating to the Canadian operations’ goodwill is reflected in the consolidated statement of income for the year ended December 31, 2002, as a cumulative effect of accounting change from discontinued operations. Revenues from these operations were $4.2 million for the year ended December 31, 2002, compared to $8.2 million for the year ended December 31, 2001.
Protection One sold all assets and liabilities of the Canadian operations. The major classes of assets and liabilities of the Canadian operations at December 31, 2001 were as follows:
28. RELATED PARTY TRANSACTIONS
Below, we describe significant transactions between us and Westar Industries and some of our other subsidiaries and related parties. We have disclosed these significant transactions even if they have been eliminated in the preparation of our consolidated results and financial position.
ONEOK Shared Services Agreement
We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support, meter reading and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses.
ONEOK gave us notice of termination effective December 2003 of this shared services agreement. We expect termination of this agreement will increase our annual costs to provide these services by approximately $11 million to $13 million.
Protection One Shared Services Agreement
We provide administrative services to Protection One pursuant to services agreements, including accounting, tax, audit, human resources, legal, purchasing, facilities and technology services. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $3.9 million in 2002, $8.1 million in 2001 and $7.3 million in 2000. These intercompany charges have been eliminated in consolidation.
Westar Energy and Protection One have entered into an amended service agreement that stipulates that if Westar Energy sells its interest in Protection One, Westar Energy and Protection One will negotiate, in good faith, the terms and conditions for continuation of the services during an agreed-upon transition period. This agreement is subject to KCC approval, which has not yet been received.
Transactions Between Westar Industries and Subsidiaries
Protection One Credit Facility
Westar Industries is the lender under Protection One’s senior credit facility. The senior credit facility was amended to increase the capacity from $155 million to $280 million during the year ended December 31, 2002. On August 26, 2002, the senior credit facility was further amended to extend the maturity date to January 5, 2004. On March 11, 2003, the KCC limited the amount of the credit facility to $228.4 million, authorized us to fund the facility and extend the term of the facility to January 5, 2005 and required the facility to be paid in full and terminated upon the disposition of all or part of our investment in Protection One. We are in discussions with Protection One about the extension of the facility and we intend to renew the facility through January 5, 2005, should such renewal be necessary to provide Protection One with continued liquidity. For further information, see Note 34.
As of December 31, 2002, $215.5 million was drawn under the facility. The remaining availability under this facility as of December 31, 2002 was $64.5 million. At March 14, 2003, Protection One had outstanding borrowings of $215.5 million and $12.9 million of remaining capacity. Amounts outstanding, accrued interest and facility fees have been eliminated in our consolidated financial statements.
Purchases of Securities
Westar Industries, Protection One and we have purchased our and Protection One’s debt securities and preferred stock in the open market. These repurchases have been accounted for as retirements on a consolidated basis. The table below summarizes these transactions for the years ended December 31, 2002, 2001 and 2000.
See Note 26 for information about a change in accounting treatment that requires that gains and losses arising from the purchases and sales of these securities be recorded as other income rather than as an extraordinary item. See Note 34 for information regarding purchases of securities that have occurred during 2003.
Tax Sharing Agreement
We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes so long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $13.5 million for tax year 2001 and $7.4 million for tax year 2000. On March 11, 2003, the KCC issued an order that allows us to make a cash payment to Protection One of approximately $20 million for tax year 2002.
Financial Advisory Services
Protection One entered into an agreement pursuant to which it paid a quarterly fee to Westar Industries for financial advisory services equal to 0.125% of its consolidated total assets at the end of each quarter. This agreement was approved by the independent members of Protection One’s board of directors. Protection One
incurred approximately $3.6 million of such fees during the year ended December 31, 2002. These amounts have been eliminated in our consolidated financial statements. This agreement was terminated effective September 30, 2002.
Loans to Officers
During 2001 and 2002, we extended loans to our officers for the purpose of purchasing shares of our common stock. The officers are personally liable for the repayment of the loans, which are unsecured and bear interest, payable quarterly, at a variable rate equal to our short-term borrowing rate. The loans mature on December 4, 2004. The aggregate balance outstanding at December 31, 2002 was approximately $1.8 million, which is classified as a reduction to shareholders’ equity in the accompanying consolidated balance sheets. For the year ended December 31, 2002, we recorded approximately $97,000 in interest income on these loans. No additional loans will be made as a result of federal legislation that became effective July 30, 2002.
Transactions Between Westar Energy and KGE
We perform KGE’s cash management function, including cash receipts and disbursements. An intercompany account is used to record net receipts and disbursements between us and KGE. KGE’s net amount payable from affiliates approximated $24.1 million at December 31, 2002, and the net amount receivable from affiliates approximated $17.3 million at December 31, 2001. These intercompany charges have been eliminated in consolidation.
We provide all employees utilized by KGE. We allocate certain operating expenses to KGE. 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.
Transactions with Protection One
During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers’ findings. This transaction was completed during June 2002. We recognized a loss of $2.6 million on this transaction, and we expected to realize annual operating cost savings of approximately $0.9 million. The cost savings will be treated as a regulatory liability in accordance with a March 26, 2002, KCC order. For the year ended December 31, 2002, we recorded $0.5 million in cost savings as a regulatory liability.
Protection One Europe
On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held by a subsidiary of Protection One, for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Cash proceeds from the transaction were used to reduce the outstanding balance owed to Westar Industries on Protection One’s revolving credit facility. No gain or loss was recorded on this intercompany transaction, and the net book value of the assets was unaffected.
29. WORK FORCE REDUCTIONS
In late 2001, we reduced our utility work force by approximately 200 employees through involuntary separations and recorded a severance-related net charge of approximately $14.3 million. In 2001, Protection One also reduced its work force by approximately 500 employees in connection with facility consolidations and recorded a severance-related net charge of approximately $3.1 million.
During 2002, we further reduced our utility work force by approximately 400 employees through a voluntary separation program. We recorded a net charge of approximately $21.7 million in 2002 related to this program. We have replaced and may continue to replace some of these employees.
30. ICE STORM
In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. Through December 31, 2002, we incurred $19.3 million for restoration costs, a portion of which was capitalized. We have deferred and recorded as a regulatory asset on our December 31, 2002 consolidated balance sheet restoration costs of approximately $15.0 million. We have received an accounting authority order from the KCC that allows us to accumulate and defer for potential future recovery all operating and carrying costs related to storm restoration.
31. POTENTIAL SALE OF UTILITY ASSETS
On October 14, 2002, we announced an agreement with Midwest Energy, Inc. (Midwest Energy) for the sale to Midwest Energy of a portion of our transmission and distribution assets and rights to provide service to customers in an area of central Kansas. The sale will affect about 10,000 customers, or about 1.5% of our total customers, over 895 square miles. The area, which includes 42 towns, is on the west edge of our service territory and is largely surrounded by Midwest Energy’s existing territory. The proposed sale is contingent upon approval by the KCC and FERC. KCC hearings have been scheduled to begin on May 20, 2003. We can give no assurance as to when or if this transaction will occur.
32. SEGMENTS OF BUSINESS
Our business is segmented based on differences in products and services, production processes and management responsibility. We have identified three reportable segments: Electric Utility, Monitored Services and Other.
•
Electric Utility consists of our integrated electric utility operations, including the generation, transmission and distribution of power to our retail customers in Kansas and to wholesale customers, and our power marketing activities.
•
Monitored Services, including the net effect of minority interests, is comprosed of our security alarm monitoring businesses in the United States and Europe.
•
Other includes our approximate 45% ownership interest in ONEOK at December 31, 2002, and other investments in the aggregate not material to our business or results of operations.
We manage our business segments’ performance based on their earnings (losses) before interest and taxes (EBIT) because EBIT is the primary measurement used by our management to evaluate segment performance. Our business managers have direct control over the items that affect the EBIT of their segments and we therefore believe EBIT is an appropriate measure of segment performance. EBIT does not represent cash flow from operations as defined by GAAP, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund our cash needs. Items excluded from EBIT are significant components in understanding and assessing our financial performance. Interest expense, income taxes, discontinued operations, cumulative effects of accounting changes and preferred dividends are items that are excluded from the calculation of EBIT. Our computation of EBIT may not be comparable to other similarly titled measures of other companies. We have no single external customer from which we receive 10% or more of our revenues.
(a)
EBIT includes a $22.9 million reserve for potential liabilities to Mr. Wittig and Mr. Lake and a $22.6 million charge recorded for marking to market changes in the fair value of the call option of the putable/callable notes.
(b)
EBIT includes $338.1 million impairment of customer accounts and $140.0 million impairment of goodwill.
(c)
EBIT includes investment earnings of $65.6 million.
(d)
Sales and goodwill are from a wholly owned subsidiary of Westar Industries providing paging services, which was sold during the first quarter of 2002.
(e)
EBIT includes earnings on investments of $38.4 million and loss on extinguishment of debt of $17.3 million.
(f)
EBIT includes the gain on the sale of our investment in a gas compression company of $91.1 million and the gain on the sale of other marketable securities of $24.9 million.
Geographic Information
Our sales and property, plant and equipment by geographic area are as follows:
33. QUARTERLY RESULTS (UNAUDITED)
The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.
34. SUBSEQUENT EVENTS
Proposed Dispositions
The Debt Reduction Plan contemplates the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. Consistent with the Debt Reduction Plan, on January 13, 2003, we announced that our board of directors authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe, and we have retained financial advisors to assist with the possible sales. A special committee comprised of independent directors of Protection One’s board of directors has been formed, and the committee has also retained a financial advisor. As a result of these decisions, these operations were classified as discontinued operations during the first quarter of 2003 pursuant to the provisions of SFAS No. 144.
As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount by which our basis exceeds the estimated fair value, which could be material.
We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.
Payments to Protection One
On March 21, 2003, we paid approximately $1.0 million to Protection One as reimbursement for information technology services provided to us, and related costs incurred, by a subsidiary of Protection One. On March 21, 2003, we also paid approximately $3.6 million to Protection One as reimbursement for aviation services provided by a subsidiary of Protection One and for the repurchase of the stock of the subsidiary. These payments were authorized by the KCC in an order issued March 11, 2003, which is described in Note 3.
Purchase of Stock from Protection One
On February 14, 2003, we purchased 850,000 shares of our common stock and approximately 34,000 shares of our preferred stock from Protection One for approximately $11.6 million. This transaction was approved by the KCC. The shares of common stock are being held as treasury stock and the shares of preferred stock have been retired. This transaction had no effect on the consolidated financial statements.
Purchases of Debt Securities
From January 1, 2003 through March 14, 2003 we purchased $35.3 million face value of our putable/callable notes and $43.0 million face value of our 6.875% senior unsecured notes in the open market.
Termination of Plane Lease
During March 2003, we terminated the lease of an airplane and incurred an expense of $5.9 million related to this termination.
35. POTENTIAL LIABILITIES TO DAVID C. WITTIG AND DOUGLAS T. LAKE
David C. Wittig, our former chairman of the board, president and chief executive officer, resigned from all of his positions with us and our affiliates on November 22, 2002. Douglas T. Lake, our executive vice president and chief strategic officer, was placed on administrative leave from all of his positions with us and our affiliates on December 6, 2002. In connection with these actions, we reserved all rights and claims we may have against Mr. Wittig and Mr. Lake arising under their employment agreements, any other agreements with us, or any plan, program or policy in which they participated. In their respective resignation and leave letters, Mr. Wittig and Mr. Lake stated that they reserved all rights and claims they may have against us.
During their active employment with us, we accrued liabilities totaling approximately $27.4 million for compensation not yet paid to Mr. Wittig and Mr. Lake under various plans. The compensation includes restricted share unit awards, deferred vested shares, deferred restricted share unit awards, deferred vested stock for compensation, executive salary continuation plan benefits and, in the case of Mr. Wittig, benefits arising from a split dollar life insurance agreement.
Additionally, as required by GAAP, we have made provisions in our financial statements for an additional amount of approximately $22.9 million should it later be determined that we are obligated to pay Mr. Wittig and Mr. Lake any amounts under their employment agreements. We do not concede, however, that any amounts are owed to
Mr. Wittig or Mr. Lake, and we believe that we may have potential claims and defenses against Mr. Wittig and Mr. Lake. The compensation could include a pro rata portion of their unpaid bonuses for the year in which termination occurred, unused vacation, accumulated sick leave, severance, restricted share unit awards and related dividend equivalents, and increased executive salary continuation plan benefits. We believe the amount reserved adequately provides for potential obligations to Mr. Wittig and Mr. Lake.
In addition to these amounts, we could also be obligated to record additional expense each year in which payments are made to Mr. Wittig and Mr. Lake pursuant to the executive salary continuation plan. Assuming an expected payout period of 35 years, the aggregate nominal amount of these expenses would be approximately $17.9 million for Mr. Wittig and $9.0 million for Mr. Lake. Also, if stock performance requirements for some restricted share unit awards were to be satisfied, we would be required to record additional compensation expense of approximately $4.4 million to Mr. Wittig and Mr. Lake.
As of March 31, 2003, neither Mr. Wittig nor Mr. Lake has asserted any rights or claims against us for any of the amounts described above. We are unable to predict whether they will assert any rights or claims in the future. If they did so, we will vigorously defend against such claims and potentially assert counterclaims; however, the ultimate resolution of these matters is outside our control.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Effective May 30, 2002, the Audit and Finance Committee of our board of directors decided not to engage Arthur Andersen LLP (Andersen) as our public accountants and engaged Deloitte & Touche LLP (Deloitte & Touche) to serve as our principal accountants for fiscal year 2002. This matter was previously reported by us on our Form 8-K dated May 30, 2002 filed with the SEC.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to our directors required by Item 10 is set forth in our definitive proxy statement to be filed with the SEC for our 2003 Annual Meeting of Shareholders to be held on June 16, 2003. Such information is incorporated herein by reference to the material appearing under the caption “Election of Directors” in the proxy statement to be filed by us with the SEC.
EXECUTIVE OFFICERS OF THE COMPANY
Name
Age
Present Office
Other Offices or Positions
Held During the Past Five Years
James S. Haines, Jr.
Director, Chief Executive Officer and President (since December 2002)
The University of Texas at El Paso -
Adjunct Professor and Skov Professor of Business Ethics (January 2002 to Present)
El Paso Electric Company -
Director, President and Chief Executive Officer (May 1996 to November 2001)
William B. Moore
Executive Vice President and Chief Operating Officer
(since December 2002)
Saber Partners, LLC -
Senior Managing Director and Senior Advisor (October 2000 to December 2002)
Westar Energy -
Executive Vice President and Chief Financial Officer, Treasurer (May 1999 to August 2000)
Acting Executive Vice President, Chief Financial Officer, Treasurer (October 1998 to May 1999)
Chairman of the Board, KGE, and President (June 1995 to October 1998)
Mark A. Ruelle
Executive Vice President and Chief Financial Officer
(since January 2003)
Sierra Pacific Resources, Inc. -
President, Nevada Power Company (June 2001 to May 2002)
Senior Vice President, Chief Financial Officer (March 1997 to May 2001)
Richard A. Dixon
Senior Vice President, Operations Strategy
(since March 2003)
Westar Energy, Inc. -
Senior Vice President, Customer Operations (October 2001 to March 2003)
Vice President, Transmission Services (May 2000 to October 2001)
Executive Director, System Operations (January 1999 to April 2000)
Executive Director, Transmission Services (September 1996 to December 1998)
Douglas R. Sterbenz
Senior Vice President, Generation and Marketing (since October 2001)
Westar Energy, Inc. -
Senior Director, Bulk Power Marketing (January 1999 to October 2001)
Manager, Bulk Power Marketing (August 1998 to December 1998)
Energy Trader (May 1997 to July 1998)
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 will be set forth in our definitive proxy statement to be filed with the SEC for our 2003 Annual Meeting of Shareholders to be held on June 16, 2003. Such information is incorporated herein by reference to the material appearing under the captions “Information Concerning the Board of Directors,” “Executive Compensation,” “Compensation Plans” and “Human Resources Committee Report” in the proxy statement to be filed by us with the SEC.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 will be set forth in our definitive proxy statement to be filed with the SEC for our 2003 Annual Meeting of Shareholders to be held on June 16, 2003. Such information is incorporated herein by reference to the material appearing under the captions “Beneficial Ownership of Voting Securities” and “Equity Compensation Plan Information” in the proxy statement to be filed by us with the SEC.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 will be set forth in our definitive proxy statement to be filed with the SEC for our 2003 Annual Meeting of Shareholders to be held on June 16, 2003. Such information is incorporated herein by reference to the material appearing under the caption “Certain Relationships and Related Transactions” in the proxy statement to be filed by us with the SEC.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing date of this report, an evaluation was carried out, under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our chief executive officer and our chief financial officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to the date of the evaluation described above.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS INCLUDED HEREIN
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 2002 and 2001
Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Comprehensive Income for the years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2002, 2001 and 2000
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
REPORTS ON FORM 8-K FILED DURING THE QUARTER ENDED DECEMBER 31, 2002:
Form 8-K filed October 1, 2002
-
Clarification of the amount of a charge expected to be included in third quarter 2002 results resulting from marking to market the amount of a liability arising from a call option related to our 6.25% senior unsecured notes issued in August 1998.
Form 8-K filed October 4, 2002
-
Announcement that our board of directors modified the Special Committee membership appointed to investigate certain matters relating to a grand jury investigation and subpoenas served by the United States Attorney’s Office in Topeka, Kansas.
Form 8-K filed November 1, 2002
-
Announcement that we will restate our first and second quarter 2002 financial statements to reflect an additional impairment at Protection One, Inc. pursuant to the application of Statement of Financial Accounting Standards Nos. 142 and 144, and to reflect a previously reported non-cash charge related to marking to market the amount of a potential liability arising from a call option related to our 6.25% senior unsecured notes issued in August 1998.
Form 8-K filed November 8, 2002
-
Announcement of the indictment of David C. Wittig, our former chairman of the board, president and chief executive officer, by a federal grand jury in Topeka, Kansas, making allegations relating to Mr. Wittig’s personal dealings and that Mr. Wittig had been placed on administrative leave.
Form 8-K filed November 15, 2002
-
Announcement that John C. Dicus retired from our board of directors.
Form 8-K filed November 25, 2002
-
Announcement that we accepted the resignation of David C. Wittig on November 22, 2002 from all of his positions with us and our subsidiaries or affiliates.
-
Announcement that James S. Haines, Jr. was appointed to our board of directors and as our chief executive officer and president, effective December 9, 2002.
Form 8-K filed December 9, 2002
-
Announcement that on December 6, 2002, Douglas T. Lake resigned as our director, as chairman of the board of Protection One, and as a director of all of our other subsidiaries and affiliates for which he serves as director. In addition, we accepted Mr. Lake’s request to be placed on leave from his position as our executive vice president and chief strategic officer, without pay.
Form 8-K filed December 27, 2002
-
Announcement that on December 23, 2002, the KCC issued an order modifying an order issued on November 8, 2002 addressing our financial plan.
-
Announcement that on December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco 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.
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.
WESTAR ENERGY, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(a)
Deductions are primarily the result of write-offs of accounts receivable.
(b)
Deductions are the result of payment of accrued severance costs.
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature
Title
Date
/s/ JAMES S. HAINES, JR.
(James S. Haines, Jr.)
Director, Chief Executive Officer and President
(Principal Executive Officer)
April 11, 2003
/s/ MARK A. RUELLE
(Mark A. Ruelle)
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
April 11, 2003
/s/ CHARLES Q. CHANDLER IV
(Charles Q. Chandler IV)
Chairman of the Board
April 11, 2003
/s/ FRANK J. BECKER
(Frank J. Becker)
Director
April 11, 2003
/s/ GENE A. BUDIG
(Gene A. Budig)
Director
April 11, 2003
/s/ R. A. EDWARDS III
(R. A. Edwards III)
Director
April 11, 2003
/s/ LARRY D. IRICK
(Larry D. Irick)
Director
April 11, 2003
/s/ JOHN C. NETTELS, JR.
(John C. Nettels, Jr.)
Director
April 11, 2003
CERTIFICATION PURSUANT TO
RULE 13a-14 UNDER THE
SECURITIES EXCHANGE ACT OF 1934
I, James S. Haines, as chief executive officer and president of the company, certify that:
1.
I have reviewed this annual report for the period ended December 31, 2002 on Form 10-K of Westar Energy, Inc.;
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a.
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b.
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c.
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a.
all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b.
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
CERTIFICATION PURSUANT TO
RULE 13a-14 UNDER THE
SECURITIES EXCHANGE ACT OF 1934
I, Mark A. Ruelle, as chief financial officer and executive vice president of the company, certify that:
1.
I have reviewed this annual report for the period ended December 31, 2002 on Form 10-K of Westar Energy, Inc.;
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a.
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b.
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c.
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a.
all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b.
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.