ITEM 1. BUSINESS - -----------------
GENERAL
Western Resources, Inc. is a publicly traded consumer services company incorporated in 1924. Unless the context otherwise indicates, all references in this report on Form 10-K to the "company," "Western Resources," "we," "us" "our" or similar words are to Western Resources, Inc. and its consolidated subsidiaries. Our primary business activities are providing electric generation, transmission and distribution services to approximately 636,000 customers in Kansas and providing monitored security services to over 1.5 million customers in North America, the United Kingdom and continental Europe. Rate regulated electric service is provided by KPL, a division of the company, and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary. Monitored security services are provided by Protection One, Inc., a publicly traded, approximately 85%-owned subsidiary, and other wholly owned subsidiaries collectively referred to as Protection One Europe. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). In addition, through our 45% ownership interest in ONEOK, Inc., natural gas transmission and distribution services are provided to approximately 1.4 million customers in Oklahoma and Kansas. Westar Industries, Inc., our wholly owned subsidiary, owns our interests in Protection One, Protection One Europe, ONEOK, and other non-utility businesses. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.
On November 8, 2000, we entered into an agreement under which Public Service Company of New Mexico (PNM) will acquire our electric utility businesses in a stock-for-stock transaction. Under the terms of the agreement, both we and PNM will become subsidiaries of a new holding company. Immediately prior to the consummation of this combination, we will split-off our remaining interest in Westar Industries to our shareholders.
Westar Industries has filed a registration statement with the Securities and Exchange Commission (SEC) which covers the proposed sale of a portion of its common stock through the exercise of non-transferable rights proposed to be distributed by Westar Industries to our shareholders.
We can give no assurance as to whether or when the rights offering will be consummated or whether or when the separation of our electric and non-electric utility businesses, or the consummation of the acquisition of the company by PNM may occur.
ELECTRIC UTILITY OPERATIONS
General
We supply electric energy at retail to approximately 636,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We also supply electric energy at wholesale to the electric distribution systems of 65 communities and 4 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 in which electric purchases and sales are made in areas outside of our historical marketing territory.
Our electric sales for the last three years ended December 31 are as follows:
2000 1999 1998 ---------- ---------- ---------- (In Thousands) Residential................... $ 452,674 $ 407,371 $ 428,680 Commercial.................... 367,367 356,314 356,610 Industrial.................... 252,243 251,391 257,186 Wholesale and Interchange.................. 214,721 174,895 145,320 Power Marketing............... 457,178 190,101 382,601 System Hedging................ 35,321 3,320 - Other......................... 49,628 46,306 41,288 ---------- ---------- ---------- Total........................ $1,829,132 $1,429,698 $1,611,685
Our electric sales volumes for the last three years ended December 31 are as follows: 2000 1999 1998 ---------- ---------- ---------- (Thousands of MWH) Residential................... 6,222 5,551 5,815 Commercial.................... 6,485 6,202 6,199 Industrial.................... 5,820 5,743 5,808 Wholesale and Interchange.................. 6,892 5,617 4,826 Other......................... 108 108 108 ------ ------ ------ Total........................ 25,527 23,221 22,756
Power marketing and system hedging sales do not have any physical sales volumes associated with them.
Fossil Fuel Generation
Capacity: The aggregate net generating capacity of our system is presently 5,604 megawatts (MW). The system has interests in 21 fossil-fuel steam generating units, one nuclear generating unit (47% interest), nine combustion peaking turbines, two diesel generators, and two wind generators. A fossil fueled unit at Lawrence Energy Center (31 MW of capacity) was retired in 2000.
Our aggregate 2000 peak system net load, which was also our all time peak system net load, occurred on September 11, 2000 and amounted to 4,531 MW. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 11.7% above system peak responsibility at the time of the peak.
We are a member of the Western Systems Power Pool (WSPP). Under this arrangement, electric utilities and marketers throughout the western United States have agreed to market energy. Services available include short-term and long-term energy transactions, unit commitment service, firm capacity, energy sales and energy exchanges. We are also a member of the Southwest Power Pool as discussed under Power Delivery.
We have agreed to provide generating capacity to other utilities for certain periods as set forth below:
Utility Capacity (MW) Period Ending ------- ------------- ------------- Oklahoma Municipal Power Authority (OMPA) 60 December 2013
Midwest Energy, Inc. 60 May 2008 125 May 2010
Empire District Electric Company (Empire) 80 May 2001 162 May 2010
McPherson Board of Public Utilities (McPherson) (a) May 2027
(a) We provide base capacity to McPherson and McPherson provides peaking capacity to us. During 2000, we provided approximately 73 MW to and received approximately 185 MW from McPherson. The amount of base capacity provided to McPherson is based on a fixed percentage of McPherson's annual peak system load.
Future Capacity: We are installing a new combustion turbine generator with a capacity of approximately 154 MW. The unit is scheduled to be placed in operation in mid-2001. We estimate that completion of the project will require approximately $20 million in capital resources during 2001. We forecast that we will need additional capacity of approximately 150 MW by 2005 to serve our customers' expected electricity needs. The methods for supplying this estimated additional energy will be determined at a future date.
In July 1999, we and Empire agreed to jointly construct a 500-MW combined cycle generating plant, which Empire will operate. We will own a 40% interest in the plant through a subsidiary, Westar Generating, Inc. We estimate that our share of the cost of completing the project will require approximately $31 million in capital resources during 2001. Commercial operation is expected to begin in mid-2001.
For further discussion regarding future capacity and cash requirements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Fuel Mix: Coal-fired units comprise 3,366 MW of our total 5,604 MW of generating capacity and the nuclear unit provides 550 MW of capacity. Of the remaining 1,688 MW of generating capacity, units that can burn either natural gas or oil account for 1,603 MW, units that burn only diesel fuel account for 84 MW, and units which are powered by wind account for 1 MW (See Item 2.
ITEM 2. PROPERTIES - -------------------
ELECTRIC GENERATING FACILITIES
(a) We jointly own Jeffrey Energy Center (84%), La Cygne 1 generating unit (50%), and Wolf Creek Generating Station (47%). (b) In 1987, KGE entered into a sale leaseback transaction involving its 50% interest in the La Cygne 2 generating unit.
We own approximately 6,300 miles of transmission lines, approximately 21,000 miles of overhead distribution lines, and approximately 2,800 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:
(1) In March 2001, this facility was closed.
Protection One Europe:
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS - --------------------------
The Securities and Exchange Commission (SEC) commenced a private investigation in 1997 relating to, among other things, the timeliness and adequacy of disclosure filings with the SEC by us with respect to securities of ADT Ltd. We are cooperating with the SEC staff in this investigation.
The company, its subsidiary Westar Industries, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Monitoring), and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Alec Garbini, et al v. Protection One, Inc., et al," No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint ("Amended Complaint"). Plaintiffs purported to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and notes, during the period of February 10, 1998 through February 2, 2001. The Amended Complaint asserts claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs allege, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Amended Complaint further asserts claims against the company and Westar Industries as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim is also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Amended Complaint seeks an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. Defendants have until April 9, 2001 to respond to the Amended Complaint. The company and Protection One intend to vigorously defend against all the claims asserted in the Amended Complaint. The company and Protection One cannot predict the impact of this litigation which could be material.
Additional information on legal proceedings involving the company is set forth in Notes 3 and 15 of Notes to Consolidated Financial Statements. See also Item 1. Business, Environmental Matters and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
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 2000.
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 19, 2001, there were 39,546 common shareholders of record. For information regarding quarterly common stock price ranges for 2000 and 1999, see Note 23 of Notes to Consolidated Financial Statements.
Dividends
Holders of our common stock are entitled to dividends when and as declared by the Board of Directors. However, prior to the payment of common dividends, dividends must be first 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 normally are paid on or about the first of January, April, July, and October to shareholders of record as of or about the ninth day of the preceding month. The company's board of directors reviews its dividend policy from time to time. Among the factors the board of directors considers in determining its dividend policy are earnings, cash flows, capitalization ratios, competition and financial loan covenants. In March 2000, the company announced a quarterly dividend of $0.30 per share (an indicated dividend rate of $1.20 per share on an annual basis). In February 2001, the company's board of directors declared a first-quarter 2001 dividend of 30 cents per share. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM.
Our Articles of Incorporation 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. At December 31, 2000, under these provisions, the company's paid-in capital and retained earnings were restricted by $857,600 against the payment of dividends on common stock.
For information regarding quarterly dividend declarations for 2000 and 1999, see Note 23 of Notes to Consolidated Financial Statements included herein. See also Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA - --------------------------------
(a) Information reflects the impairment of marketable securities and the change to an accelerated amortization method for Monitored Services customer accounts. (b) Information reflects exit costs associated with international power development activities. (c) Information reflects the gain on the sale of Tyco common shares, our strategic alliance with ONEOK and the acquisition of Protection One. (d) In March 2000, the company announced a new dividend policy. See Item 5. Dividends.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND - ------------------------------------------------------------------------ RESULTS OF OPERATIONS ---------------------
INTRODUCTION
Unless the context otherwise indicates, all references in this report on Form 10-K to the "company," "Western Resources," "we," "us," "our" or similar words are to Western Resources, Inc. and its consolidated subsidiaries.
In Management's Discussion and Analysis we explain the general financial condition, significant annual changes and the operating results for Western Resources and its subsidiaries. We explain:
- What factors impact our business - What our earnings and costs were in 2000 and 1999 - Why these earnings and costs differ from year to year - How our earnings and costs affect our overall financial condition - What our capital expenditures were for 2000 - What we expect our capital expenditures to be for the years 2001 through 2003 - How we plan to pay for these future capital expenditures - 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 which show our operating results.
SUMMARY OF SIGNIFICANT ITEMS
PNM Merger and Split-off of Westar Industries
On November 8, 2000, we entered into an agreement under which Public Service Company of New Mexico (PNM) will acquire our electric utility businesses in a stock-for-stock transaction. Under the terms of the agreement, both we and PNM will become subsidiaries of a new holding company. Immediately prior to the consummation of this combination, we will split-off our remaining interest in Westar Industries to our shareholders. Westar Industries, our wholly owned subsidiary, owns our interests in Protection One, Inc., Protection One Europe, ONEOK, Inc., and other non-utility businesses. In connection with this transaction, in February 2001 Westar Industries converted a portion of a receivable owed by us into approximately 14.4 million shares of our common stock. See Note 2 of the Notes to Consolidated Financial Statements.
Westar Industries has filed a registration statement with the Securities and Exchange Commission (SEC) covering the proposed sale of a portion of its common stock through the exercise of non-transferable rights proposed to be distributed by Westar Industries to our shareholders. We anticipate that the rights offering will be completed in 2001.
We can give no assurance as to whether or when the rights offering will be consummated or whether or when the separation of our electric and non-electric utility businesses, or the consummation of the acquisition of the company by PNM may occur.
Extraordinary Gain on Extinguishment of Debt
During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 million of these debt securities were transferred to Protection One. Protection One also purchased $30.5 million face value of its bonds on the open market during 2000. An extraordinary gain of $49.2 million, net of tax of $26.5 million, was recognized at December 31, 2000, on these retirements.
Exposure Draft for Goodwill Accounting
The Financial Accounting Standards Board (FASB) issued an exposure draft on February 14, 2001 which, if adopted as proposed, would establish a new accounting standard for the treatment of goodwill in a business combination. The new standard would continue to require recognition of goodwill as an asset in a business combination but would not permit amortization as currently required by APB Opinion No. 17, "Intangible Assets." The new standard would require that goodwill be separately tested for impairment using a fair-value based approach as opposed to an undiscounted cash flow approach which is required under current accounting standards. If goodwill is found to be impaired, we would be required to record a non-cash charge against income. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds the fair value. Goodwill would no longer be amortized on a current basis as is required under current accounting standards. The exposure draft contemplates this standard to become effective on July 1, 2001, although this effective date is not certain. Furthermore, the proposed standard could be modified prior to its adoption.
If the new standard is adopted as proposed, any subsequent impairment test on our customer accounts would be performed on the customer accounts alone rather than in conjunction with goodwill utilizing an undiscounted cash flow test pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of."
At December 31, 2000, we had $976 million in goodwill attributable to acquisitions of businesses and $1,006 million for monitored services' customer accounts. These intangible assets together represented 25.5% of the book value of our total assets. We recorded approximately $61.4 million in goodwill amortization expense in 2000. If the new standard becomes effective July 1, 2001 as proposed, we believe it is probable that we would be required to record a non-cash impairment charge. We cannot determine the amount at this time, but we believe the amount would be material and could be a substantial portion of our intangible assets. This impairment charge would have a material adverse effect on our operating results in the period recorded.
Strategic Transaction and the Separation of Westar Industries
Our strategic plans contemplate the acquisition of our electric utility businesses by PNM and the split-off of Westar Industries to our shareholders. Prior to the completion of these transactions, Westar Industries intends to sell a portion of its common stock in a rights offering to our shareholders. The completion of these transactions is subject to the satisfaction of various conditions, including the receipt of shareholder and regulatory approvals in the case of the PNM transaction. We can give no assurance that the conditions to closing will be satisfied and that the transactions will be consummated as contemplated. Futhermore, if the Westar Industries rights offering is completed, we would record a non-cash charge against income equal to the difference between the book value of the portion of our investment in Westar Industries sold in the rights offering and the offering proceeds received by Westar Industries. Similarly, if the split-off of Westar Industries is completed, we would record a non-cash charge against income equal to the difference between the book value of our remaining investment in Westar Industries and the fair market value of the shares of Westar Industries common stock distributed to our shareholders. We are unable to determine the amount of the charges at this time because the subscription price in the rights offering has not been determined and the fair market value of the common stock of Westar Industries distributed in the split- off will be determined at the time of the split-off. However, the charges would be material and would have a material adverse effect on our operating results in the period recorded.
Monitored Services Change in Estimate of Useful Life of Goodwill
In January 2000, Protection One re-evaluated the original assumptions and rationale utilized in the establishment of the carrying value and estimated useful life of goodwill. Protection One concluded that due to continued losses, increased levels of attrition experienced in 1999 and other factors, the estimated useful life of goodwill should be reduced from 40 years to 20 years as of January 1, 2000. After that date, remaining
goodwill, net of accumulated amortization, is being amortized over its remaining useful life based on a 20-year life. Protection One Europe made a similar change. Based on Protection One's and Protection One Europe's existing account bases at January 1, 2000, this resulted in an increase in aggregate annual goodwill amortization of approximately $33.0 million in 2000.
Marketable Securities
During the fourth quarter of 1999, we decided to sell our remaining marketable security investments in paging industry companies. These securities were classified as available-for-sale; therefore, changes in market value were historically reported as a component of other comprehensive income.
The market value for these securities declined during the last six to nine months of 1999. We determined that the decline in value of these securities was other than temporary and a charge to earnings for the decline in value was required at December 31, 1999. Therefore, a non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in the accompanying Consolidated Statements of Income.
During the first quarter of 2000, we sold the remainder of our portfolio of paging company securities. We realized a gain of $24.9 million on these sales. This gain was largely attributable to a general increase in the market value of paging companies triggered by an announcement made by one paging company in February 2000 which had a favorable impact on the market value of public paging company securities.
During 2000, we sold our equity investment in a gas compression company and realized a pre-tax gain of $91.1 million.
OPERATING RESULTS
Western Resources Consolidated
2000 Compared to 1999: Basic earnings per share was $1.96 compared to $0.20 in 1999. This increase is primarily attributable to increased investment earnings from the sale of certain investments and the extraordinary gain on the retirement of Protection One bonds. This increase was partially offset by a change in the estimated life of goodwill and operating losses from our monitored services segment.
1999 Compared to 1998: Basic earnings per share was $0.20 compared to $0.48 in 1998. Our 1999 results of operations benefited from the performance of the regulated electric utility operations. However, this performance was not sufficient to offset the impairment recorded on marketable securities in the fourth quarter of 1999 or the losses from our monitored services segment.
The following discussion explains significant changes from prior year results in sales, costs of sales, operating expenses, other income (expense), interest expense, income taxes, and preferred dividends.
Electric Utility
We supply electric energy at retail to approximately 636,000 customers in Kansas. We also supply electric energy at wholesale to the electric distribution systems of 65 communities and 4 rural electric cooperatives. We have contracts for the sale, purchase or exchange of electricity with other utilities.
In addition, we have power marketing operations and we engage in system hedging transactions. Power marketing transactions are electric purchases and sales made in areas outside of our historical marketing territory. System hedging transactions are entered into at certain times to reduce exposure relative to the volatility of market prices for purchased power. The settlement of system hedging transactions affects both our sales and our cost of sales although the net effect in 2000 was insignificant. If the cost of settling the hedging transactions exceeds the premiums from the related sales, the net effect will be a loss just as there would be a net gain if the premiums from the sales exceed the corresponding cost of the sales.
Many things will affect our future electric sales. They include:
- The weather - Our electric rates - Competitive forces - Customer conservation efforts - Wholesale demand - The overall economy of our service area - The City of Wichita's attempt to create a municipal electric utility - The cost of fuel and purchased power included in base rates - The results of our power marketing and system hedging transactions
Our electric sales for the last three years are as follows:
The following tables reflect the changes in electric sales volumes, as measured by megawatt hours, for the years ended December 31, 2000, 1999 and 1998:
Power marketing and system hedging sales do not have any physical sales volumes associated with them.
2000 compared to 1999: Electric operations gross profit increased $28.3 million, or 3%. The increase is due primarily to increased power marketing sales. Electric operations gross profit as a percentage of sales decreased to 54% from 67% primarily due to higher fuel and purchased power prices. (See Market Risk Disclosure for further discussion.)
Additionally, we experienced a 12% increase in residential sales volumes and a 23% increase in wholesale sales volumes. The increase in residential sales is primarily due to increased demand caused by warm weather. Cooling- degree days increased by 27%. The increase in wholesale sales volumes was primarily due to increased wholesale market opportunities because of our larger trading operation.
Items included in energy cost of sales are fuel expense, purchased power expense (electricity we purchase from others for resale) and power marketing expense.
Partially offsetting the higher sales was an increase of $371.3 million in cost of sales primarily due to higher power marketing expense of $263.0 million and increased fuel and purchased power expenses of approximately $71.0 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale sales volumes.
1999 compared to 1998: Electric utility gross profit increased 3%, or $30.5 million. Gross profit as a percentage of sales improved to 67% from 57%. These improvements were due primarily to increased power marketing profit and increased wholesale sales. In the summer of 1999, we had increased power plant availability during hot weather when demand was high which allowed increased wholesale sales. Power plant availability impacts both gross profit and gross profit percentage, as it is more profitable for us to generate electricity for resale than to purchase power for resale. Partially offsetting these increases were lower retail sales due to weather which was milder in 1999.
BUSINESS SEGMENTS
Our business is segmented based on differences in products and services, production processes, and management responsibility. Based on this approach, we have identified four reportable segments: Fossil Generation, Nuclear Generation, Power Delivery and Monitored Services. We also have other non-utility operations and our ONEOK investment.
Fossil Generation produces power for sale internally to the Power Delivery segment and externally to wholesale customers. Power marketing and system hedging are components of our Fossil Generation segment. Nuclear Generation represents our 47% ownership in the Wolf Creek nuclear generating facility. This segment has only internal sales because it provides all of its power to its co-owners. The Power Delivery segment consists of the transmission and distribution of power to our retail customers in Kansas and the customer service provided to these customers and the transmission of wholesale energy. Monitored Services represents our security alarm monitoring business in North America and Europe.
We manage our business segments' performance based on their earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by generally accepted accounting principles, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund the cash needs of our company. Items excluded from EBIT are significant components in understanding and assessing the financial performance of our company. We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by our company to satisfy its debt service obligations, capital expenditures, dividends and other operational needs, as well as to provide funds for growth. Our computation of EBIT may not be comparable to other similarly titled measures of other companies.
The following tables reflect key information for our three electric utility business segments:
(a) Our 47% share of Wolf Creek's operating results.
Fossil Generation
Fossil Generation's external sales include power produced for sale to external wholesale customers located outside our historical marketing territory and the amounts associated with the system hedging transactions discussed above. Internal sales include power produced for sale to Power Delivery which delivers the power to our retail and wholesale customers. The internal transfer price for these sales is set by us based upon what we believe would be competitive market prices for capacity and energy at the time of sale.
2000 compared to 1999: External sales increased $340.2 million primarily due to power marketing sales which increased by $267.1 million, wholesale sales which increased by $39.8 million and system hedging sales which increased by $32.0 million. Since 1997, we have gradually increased the size of our power trading operation in an effort to better utilize our market knowledge and to mitigate the risk associated with energy prices.
While sales increased significantly, EBIT was $16.3 million lower because of higher cost of sales. Cost of sales was $371.3 million higher primarily due to higher power marketing expense of $263.0 million, increased fuel and purchased power expenses of approximately $71.0 million and system hedging transaction costs of approximately $33.1 million.
Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale sales volumes.
The cost of fuel was significantly affected by increased gas costs of $13.3 million (despite a 9% reduction in MMBtu of gas burned). Our average natural gas price increased 45% during the year compared to 1999. Additionally, coal costs increased by $35.1 million primarily due to increasing the quantities of coal burned in our efforts to minimize gas costs and cost of oil increased $7.2 million primarily due to increased price and increasing the quantities of oil burned. See the Market Risk Disclosure in Item 7. Management's Discussion and Analysis for further discussion.
1999 compared to 1998: External sales decreased $160.7 million, or 31%, primarily due to lower power marketing sales. Power marketing sales decreased $189.2 million, or 50%, due to milder weather compared to 1998. In 1999 and 1998, the wholesale power market experienced extreme volatility in prices and supply. This volatility impacts our cost of power purchased and our participation in power trades.
The decrease in power marketing sales was partially offset by higher wholesale sales of $29.6 million. Due to warmer than normal weather throughout the Midwest in July and increased availability of our coal-fired generation stations, we were able to sell more electricity to wholesale customers in 1999 than in 1998. During the summer of 1998, one of our coal-fired generation units was unavailable for an extended period of time, reducing our wholesale sales capacity.
The internal transfer price Fossil Generation charged Power Delivery was higher due to a higher forecasted peak demand. Therefore, internal sales and EBIT of Fossil Generation were higher. EBIT was also higher due to improved net profit on power marketing transactions.
Nuclear Generation
Nuclear generation has only internal sales because it provides all of its power to its co-owners: KGE, Kansas City Power and Light Company, and Kansas Electric Power Cooperative, Inc. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Internal sales are priced at the internal transfer price that Nuclear Generation charges to Power Delivery.
Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. The next outage is scheduled in the spring of 2002. During an outage, Wolf Creek produces no power for its co-owners; therefore internal sales, EBIT and nuclear fuel expense decrease.
2000 compared to 1999: Wolf Creek shut down on September 29, 2000, for its eleventh scheduled refueling and maintenance outage. Internal sales and EBIT declined immaterially because both periods had scheduled refueling and maintenance outages.
1999 compared to 1998: Internal sales and EBIT decreased primarily due to the scheduled 36-day refueling and maintenance outage at Wolf Creek in 1999. In 1998, Wolf Creek operated the entire year without any refueling outages.
Power Delivery
The Power Delivery segment's external sales consist of the transmission and distribution of power to our electric retail and wholesale customers and the customer service provided to them. Internal sales consist of the intra-segment transfer price charged to Fossil Generation and Nuclear Generation for the use of the distribution lines and transformers.
2000 compared to 1999: External sales increased $59.2 million, or 6% and EBIT increased $26.3 million, or 18%. We experienced a 12% increase in residential sales volumes primarily due to a 27% increase in cooling degree days and a 15% increase in heating degree days which increased the demand for power on our system.
1999 compared to 1998: External sales decreased $21.3 million due primarily to 2% lower retail electric sales volumes. Retail sales volumes decreased primarily as a result of milder temperatures in 1999 than in 1998. Our service territories averaged 22% fewer cooling degree days in 1999. The cumulative effect of the electric rate decreases implemented on June 1, 1998, and June 1, 1999, reduced sales by approximately $10 million.
Internal sales were $227 million higher due to a change in the internal transfer price charged for the use of the distribution lines and transformers.
EBIT decreased $50.8 million primarily due to $21.3 million lower external sales, a $16.1 million higher internal transfer price charged by Fossil Generation and $8.3 million in ancillary service fees charged by Fossil Generation. Ancillary services include such items as voltage stabilization and spinning reserve. No ancillary service fees were charged by Fossil Generation in 1998. The increased internal transfer price was due to higher peak demand to accommodate air conditioning load.
Monitored Services
Protection One and Protection One Europe comprise our monitored services business. The results discussed below reflect monitored services on a stand- alone basis. These results do not take into consideration Protection One's minority interest of approximately 15% at December 31, 2000, 1999 and 1998.
2000 compared to 1999: Sales decreased $61.2 million primarily due to a decline in customer base and the effect of the adoption of Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB 101). Adoption of SAB 101 reduced revenue by $10.9 million. In North America, Protection One had a net decrease of 141,527 customers in 2000 as compared to a net increase of 8,595 customers in 1999. The decrease in customers is primarily attributable to the fact that Protection One's present customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace accounts lost through attrition. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce attrition become more successful than they have been to date. Until Protection One is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. Protection One's focus remains on the completion of its current infrastructure projects, the development of cost effective marketing programs, the development of its commercial business and the generation of positive cash flow. Protection One Europe had a net increase of 9,115 customers. The increase is primarily due to internal marketing efforts.
EBIT decreased $70.7 million due to lower sales, higher cost of sales and lower other income. Cost of sales increased $5.6 million due to increased compensation costs for additional personnel hired at Protection One's monitoring centers, an increase in the cost of parts and materials, and increased vehicle costs. Other income decreased because Protection One recorded a $17.2 million gain on the sale of the Mobile Services Group in the third quarter of 1999.
Depreciation and amortization expense increased by $12.9 million primarily due to the change in the estimated life of goodwill which was reduced from 40 years to 20 years.
Operating and maintenance expense decreased $13.6 million primarily due to declines in third party monitoring costs, signs and decals, printing and compensation expenses. These decreases are a direct result of the significant decline in the number of new accounts acquired during 2000 primarily due to the restructuring of Protection One's dealer program.
1999 compared to 1998: Monitored services had a net increase of 63,611 customers in 1999 as compared to a net increase of 544,521 customers in 1998. Accordingly, results for 1999 include a full year of operations with the customers added throughout 1998. The increase in customers is the primary reason for the $178.0 million increase in external sales.
EBIT decreased $53.6 million due to higher cost of sales as a result of increased customers, higher depreciation and amortization expense and higher selling general and administrative expenses.
Depreciation and amortization expense increased $108.8 million. In 1999, Protection One and Protection One Europe changed their customer amortization method from a 10-year straight line method to a 10-year declining balance method for most of the North American and European customers. This change increased amortization expense by approximately $39.2 million. The balance of the increase is primarily attributed to a full year of amortization expense on customers acquired during 1998. See Note 1 of Notes to Consolidated Financial Statements for further discussion.
Selling, general and administrative expenses increased $71.5 million primarily due to costs associated with the overall increase in the average number of customers billed, additional bad debt expense of approximately $10.5 million resulting from higher attrition, costs associated with Year 2000 compliance, professional fees and salary increases.
Western Resources Consolidated
Other Operating Expenses
In 1999, we recorded a charge of $17.6 million for deferred KCPL merger costs related to the termination of the KCPL merger.
In 1998, we recorded a $98.9 million charge to income associated with our decision to exit the international power project development business. See Note 17 of Notes to Consolidated Financial Statements for further discussion.
Other Income (Expense)
2000 compared to 1999: Other income increased $214.4 million primarily due to a $91.1 million gain on the sale of our remaining investment in a gas compression company and a $24.5 million gain on the sale of marketable securities. Other income also improved in 2000 because of a special charge of $76.2 million we recorded in 1999 related to our paging securities portfolio. These increases were partially offset by a decrease in other income due to the $17.2 million gain on the sale of Protection One's Mobile Services Group recorded in the third quarter of 1999.
1999 compared to 1998: Other income for 1999 decreased $57.3 million primarily due to the impairment charge for an other than temporary decline in the value of marketable securities recorded in 1999 as discussed above.
Interest Expense
2000 compared to 1999: Interest expense represents the interest we paid on outstanding debt. We retired long-term debt during 1999 and 2000, causing long- term debt interest expense to decrease by $10.0 million for the year ended December 31, 2000. The retirements included $125 million of Western Resources' first mortgage bonds in 1999 and $75 million in 2000. We also retired Protection One bonds in the fourth quarter of 1999 and during 2000 with an aggregate face value of $290.4 million. For more information, see the Liquidity and Capital Resources section below.
Short-term debt interest expense was $5.5 million higher due to increased short-term borrowings under our credit facilities. The majority of this short- term debt was repaid in the third quarter of 2000 with proceeds from the $600 million term loan.
1999 compared to 1998: Interest expense increased 30% primarily due to Protection One incurring additional long-term debt to fund purchases of customer accounts. We also had higher long-term debt interest expense because of the 6.25% and 6.8% unsecured senior notes due in 2018 that we issued in the third quarter of 1998. Short-term debt interest expense was $2.4 million higher due to higher average balances of short-term debt in 1999.
Income Taxes
2000 compared to 1999: We had income tax expense of $46.1 million in 2000 compared to an income tax benefit of $32.2 million in 1999. Our effective income tax rates were 33.6% for December 31, 2000 and (108.6%) for December 31, 1999. This change is primarily due to earnings before income taxes in 2000 compared to a loss before income taxes in 1999. Earnings before income taxes increased primarily due to the $115.6 million gain on the sale of investments.
In 1999, our loss before income taxes included an impairment charge for marketable securities and the charge related to the termination of the KCPL merger.
In 2000, we also had tax expense of $26.5 million related to our extraordinary gain on the purchase of Protection One bonds.
The difference between our effective tax rate and the statutory rate is primarily attributable to the tax benefit of excluding from taxable income, in accordance with IRS rules, 70% of the dividends received from ONEOK, the generation and utilization of tax credits from affordable housing investments, the amortization of prior years' investment tax credits, the amortization of non-deductible goodwill, the tax benefits from corporate-owned life insurance and the deduction for state income taxes.
1999 compared to 1998: We have recorded an income tax benefit in 1999 of $32.2 million and income tax expense in 1998 of $6.8 million. This change is primarily due to lower earnings before income taxes in 1999. Earnings before income taxes decreased primarily due to operating results at Protection One, the impairment of marketable securities discussed above and the charge related to the termination of the KCPL merger.
We also had tax expense of $7.2 million related to Westar Industries' extraordinary gain on the purchase of Protection One bonds, which is presented on the consolidated statement of income after income from continuing operations.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion explains significant factors in liquidity and capital resources at December 31, 2000.
Overview
Most of our cash requirements consist of capital expenditures and maintenance costs associated with the electric utility business, cash needs of our monitored services business, debt service and cash payments of common stock dividends. Our ability to attract necessary financial capital on reasonable terms is critical to our overall business plan. Historically, we have paid for these items with cash on hand and the issuance of stock or long- or short-term debt. Our ability to provide the cash, stock or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions.
We had $8.8 million in cash and cash equivalents at December 31, 2000. We consider cash equivalents to be highly liquid debt instruments when purchased with a maturity of three months or less. We also had $22.2 million of restricted cash classified as a current asset. The current asset portion of our restricted cash consists primarily of cash held in escrow as required by certain letters of credit. In addition, we had $35.9 million of restricted cash classified as a long-term asset which consists primarily of cash held in escrow required by the terms of a pre-paid capacity and transmission agreement.
At December 31, 2000, current maturities of long-term debt were $41.8 million and short-term debt outstanding was $35.0 million. At March 19, 2001, our short-term debt outstanding was $72.0 million.
On June 28, 2000, we entered into a $600 million, multi-year term loan that replaced two revolving credit facilities which matured on June 30, 2000. The net proceeds of the term loan were used to retire short-term debt. The term loan is secured by first mortgage bonds of the company and KGE and has a final maturity date of March 17, 2003.
Maturities of the term loan through March 17, 2003, are as follows:
Principal Year Amount ---- --------- (In Thousands) 2001.................... $ 9,000 2002.................... 6,000 2003.................... 585,000 --------- $ 600,000
The terms of the loan contain requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. We are in compliance with all of these requirements.
Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. The weighted average interest rate, including amortization of fees, on the term loan for the year ending December 31, 2000 was 10.28%.
We also have an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by first mortgage bonds of the company and KGE and matures on March 17, 2003. Borrowings on this facility were $35.0 million at December 31, 2000 and $72.0 million at March 19, 2001. Under the terms of the agreement, we are required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. We are in compliance with this restriction.
We have registered securities for sale with the Securities and Exchange Commission (SEC). As of December 31, 2000, these included $400 million of unsecured senior notes, $500 million of our first mortgage bonds, $50 million of KGE first mortgage bonds and approximately 11.2 million of our common shares.
Our ability to issue additional debt and equity securities is restricted under limitations imposed by the Articles of Incorporation and the Mortgage and Deed of Trusts of Western Resources and KGE.
Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our 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, or 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, 2000, $39 million of first mortgage bonds (at an assumed interest rate of 9.5%) could be issued under the most restrictive provisions in the mortgage.
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, 2000, approximately $242 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
S&P, Fitch Investors Service (Fitch) and Moody's 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 these securities.
As of March 15, 2001, ratings with these agencies are as follows:
Western Protection Protection Resources' Western KGE's One's One's Mortgage Resources Mortgage Senior Senior Bond Unsecured Bond Unsecured Subordinated Rating Agency Rating Debt Rating Debt Unsecured Debt - ------------- --------- --------- --------- ---------- -------------- S&P BBB- BB- BB+ B+ B- Fitch BB+ BB BB+ B+ B- Moody's Ba1 Ba2 Ba1 B3 Caa2
Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non- utility businesses.
Following the announcement on November 9, 2000, of an agreement under which PNM will acquire our electric utility businesses, S&P revised its Credit Watch for us from developing to positive. Moody's has also upgraded its outlook from negative to positive. Fitch also revised our Rating Watch from negative to evolving after the November 2000 announcement.
On March 24, 2000, Moody's downgraded its ratings on Protection One's outstanding securities and on March 9, 2001, Moody's further downgraded these ratings citing concerns regarding Protection One's operations, leverage and liquidity over the intermediate term, with outlook remaining negative. S&P and Fitch currently have Protection One's ratings on negative watch.
Sale of Accounts Receivable
On July 28, 2000, we and KGE entered into an agreement to sell, on an ongoing basis, all of our accounts receivable arising from the sale of electricity, to WR Receivables Corporation, a special purpose entity wholly owned by the company. The agreement expires on July 26, 2001, and is annually renewable upon agreement by both parties. The special purpose entity has sold and, subject to certain conditions, may from time to time sell, up to $125 million (and upon request, subject to certain conditions, up to $175 million) of an undivided fractional ownership interest in the pool of receivables to a third-party, multi-seller receivables funding entity affiliated with a lender. Our retained interests in the receivables sold are recorded at cost which approximates fair value. We have received net proceeds of $115.0 million as of December 31, 2000.
Cash Flows from Operating Activities
Cash from operations decreased to $286.1 million for the year ended December 31, 2000, from $368.4 million for the same period of 1999. The primary reasons for this decrease are income taxes paid on the sale of marketable securities in 2000 and cash required to be escrowed in 2000 for certain contractual agreements as discussed in Liquidity and Capital Resources. Changes in working capital also contributed to this decrease in cash flow from operations.
Cash Flows (used in) Investing Activities
Investing activities used net cash flow of $86.0 million in 2000. The proceeds from the sale of marketable securities of approximately $218.6 million were offset by $308.1 million of capital additions which included costs associated with two new combustion turbine generators which were placed in service in June 2000.
Investing activities used net cash flow of $467.1 million in 1999 primarily due to net additions to property, plant and equipment of approximately $275.7 million and Protection One's use of approximately $268.4 million for customer account and security alarm business acquisitions.
Cash Flows (used in) from Financing Activities
We had a net use of cash for financing activities totaling $202.4 million during 2000 due primarily to net payments on short-term and long-term debt and dividend payments. In June 2000, we received $600 million of proceeds on a multi-year term loan, which was used to replace two revolving credit facilities, which matured at the end of the second quarter. The proceeds from the sale of marketable securities and accounts receivable were also used to reduce short- term debt and to retire long-term debt.
We had net cash provided from financing activities totaling $93.3 million during 1999 due primarily to proceeds of short-term and long-term debt of $408.9 million offset by payments on long-term debt totaling $198.0 million and dividend payments of $145.0 million.
Debt and Equity Repurchase Plans
We and Protection One may from time to time purchase our and Protection One's debt and equity securities in the open market or through negotiated transactions. The timing and terms of purchases, and the amount of debt or equity actually purchased, will be determined by the company and Protection One based on market conditions and other factors.
Future Cash Requirements
We believe that internally generated funds and access to capital markets will be sufficient to meet our operating and capital expenditure requirements, debt service and dividend payments through the year 2003. Uncertainties affecting our ability to meet these requirements include the factors affecting sales described above, the impact of inflation on operating expenses, regulatory actions, the proposed change in accounting for goodwill, the rights offering, compliance with future environmental regulations, municipalization efforts by the City of Wichita, the pending rate applications and the impact of our monitored services' operations and financial condition.
Additionally, our ability to access capital markets will affect the new and existing credit agreements we have available to meet our operating and capital expenditure requirements, debt service and dividend payments. We have $747 million of long-term debt and a $500 million revolving credit facility that will mature in 2003. Additionally, we have $400 million of putable/callable bonds that may either mature in August 2003 or be remarketed and repriced at our current credit spread and mature in 2018. We believe we will be successful in refinancing these obligations but can make no assurance that these financings will be completed at similar costs to maturing debt or at all.
We are constructing a new combustion turbine generator with an installed capacity of approximately 154 MW. The unit is scheduled to be placed in operation in mid-2001. We estimate that completion of the project will require approximately $20 million in capital resources during 2001.
We forecast that we will need additional capacity of approximately 150 MW by 2005 to serve our customer's expected electricity needs. The methods for supplying this additional energy will be determined at a future date.
In July 1999, we and Empire District Electric Company (Empire) agreed to jointly construct a 500-MW combined cycle generating plant, which Empire will operate. We will own a 40% interest in the plant through a subsidiary, Westar Generating, Inc. which will be entitled to 40% of the plant's capacity. We estimate that our share of the cost of completing the project will require approximately $31 million in capital resources during 2001. Commercial operation is expected to begin in mid-2001.
Our business requires significant capital investments. We currently expect that through the year 2003, we will need cash mostly for:
- Ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. - Improving operations within the monitored services business and the acquisition of customer accounts.
Capital expenditures for 2000 and anticipated capital expenditures for 2001 through 2003 are as follows:
Fossil Nuclear Power Monitored Generation Generation Delivery Services Other Total ---------- ---------- -------- --------- ------- -------- (In Thousands) 2000. . . $162,600 $25,900 $97,000 $ 69,500 $ 2,900 $357,900 2001. . . 110,700 16,700 89,300 92,900 200 309,800 2002. . . 76,600 19,900 97,100 101,300 - 294,900 2003. . . 70,400 29,400 96,000 134,900 - 330,700
Monitored Services includes capital expenditures for Protection One and Protection One Europe, including purchases of customer accounts. Other represents our commitment to fund our affordable housing tax credit program.
These estimates are prepared for planning purposes and will be revised from time to time. See Note 6 of Notes to Consolidated Financial Statements. Actual expenditures are likely to differ from our estimates.
Maturities of long-term debt as of December 31, 2000 are as follows:
Principal Year Amount ------------------------------- (In Thousands) 2001 . . . . . . . . $ 41,825 2002 . . . . . . . . 116,705 2003 . . . . . . . . 747,207 2004 . . . . . . . . 370,617 2005 . . . . . . . . 313,007 Thereafter . . . . . 1,683,819 ---------- $3,273,180
Capital Structure
Our capital structure at December 31, 2000 and 1999 was as follows:
2000 1999 ---- ---- Shareholders' Equity........................ 35% 38% Preferred stock............................. 1 1 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trust holding solely company subordinated debentures.... 4 4 Long-term debt.............................. 60 57 ---- ---- Total..................................... 100% 100%
Dividend Policy
Our board of directors reviews our 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, competition and financial loan covenants. Provisions in our Articles of Incorporation 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. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM.
OTHER INFORMATION
Electric Utility
City of Wichita Municipalization Efforts: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material.
KGE's franchise with the City of Wichita to provide retail electric service expires in March 2002. 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, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 25% of our total energy sales.
KCC Rate Proceedings: On November 27, 2000, we and KGE filed applications with the KCC for a change in retail rates which included a cost allocation study and separate cost of service studies for our KPL division and KGE. We and KGE also provided revenue requirements on a combined company basis on December 28, 2000. If approved as proposed, the impact of these rate requests will be an annual increase of $93.0 million for our KPL division and $58.0 million for KGE for a total of $151.0 million. The proposal also contains a mechanism for adjusting these rate requests up or down if projected natural gas fuel prices are different from the prices utilized in the November 27, 2000 filings. We anticipate a ruling by the KCC in July 2001 but are unable to predict its outcome. We can give no assurance that these rate requests will be approved as proposed.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between our KPL division and KGE, our wholly owned subsidiary. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. A hearing on the case was held at FERC on October 11 and 12, 2000 and on November 9, 2000, a FERC administrative law judge ruled in our favor that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we filed a brief opposing the city's position. We anticipate a decision by FERC in the second quarter of 2001. A decision requiring equalization of rates could have a material adverse effect on our business and financial condition.
Competition and Deregulation: The United States electric utility industry is evolving from a regulated monopolistic market to a competitive marketplace. During 2000 and early 2001, extensive problems in the deregulated California market have made many states reconsider deregulation efforts. Various states have taken steps to allow retail customers to purchase electric power from providers other than their local utility company. Several bills promoting deregulation were introduced to the Kansas Legislature in the 1999 legislative session, but none passed. No bills were considered in the legislature during the 2000 legislative session. Based on these events, we do not anticipate deregulation to occur in Kansas in the near term.
The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. During 2000, traditional wholesale electric sales, excluding power marketing sales, represented approximately 12% of total electric sales. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order 2000) encouraging formation of regional transmission organizations (RTOs), whose purpose is to facilitate greater competition at the wholesale level. We are a member of the Southwest Power Pool (SPP) which filed a second request with FERC in October 2000 to seek RTO recognition which reflects FERC comments to the SPP's first request. We anticipate that FERC Order 2000 will not have a material effect on us or our operations.
If retail wheeling is implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Wholesale and industrial customers may pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to cut their energy costs. Our rates range from approximately 5% to 24% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales volumes in a competitive environment.
Stranded Costs: The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets which 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 fossil generation, nuclear generation and power delivery operations. If we determine that we no longer meet the criteria of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to earnings. Reasons for discontinuing SFAS 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred and a significant change by regulators from a cost-based rate regulation to another form of rate regulation and the impact should the City of Wichita municipalization efforts be successful. We periodically review SFAS 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS 71 accounting treatment based upon competitive or other events, such as the successful municipalization efforts by areas we serve, we may significantly impact the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek.
Regulatory changes, including competition or successful municipalization efforts by the City of Wichita, could adversely impact our ability to recover our investment in these assets. As of December 31, 2000, we have recorded regulatory assets which are currently subject to recovery in future rates of approximately $327.4 million. Of this amount, $187.3 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 or because of such successful municipalization efforts, 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.
Nuclear Decommissioning: Decommissioning is a nuclear industry term for the permanent shut-down of a nuclear power plant. The Nuclear Regulatory Commission (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 during the estimated remaining life of the related nuclear power plant.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000.
The FASB is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. The FASB has issued an Exposure Draft "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." The FASB expects to issue a final statement of financial accounting standard in the second quarter of 2001. The proposed Exposure Draft contains an effective date of fiscal years beginning after June 15, 2001. However, the ultimate effective date has not been finalized. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur:
- Our annual decommissioning expense could be higher than in 2000 - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant
We do not believe that such changes, if required, would adversely affect our operating results due to our current ability to recover decommissioning costs through rates. See Note 14 of the Notes to Consolidated Financial Statements.
Monitored Services
Attrition: Customer attrition has a direct impact on Protection One's and Protection One Europe's results of operations since it affects revenues, amortization expense and cash flow. Any significant change in the pattern of their historical attrition experience would have a material effect on the results of operations.
Customer attrition for the years ended December 31, 2000 and 1999 is summarized below:
Customer Account Attrition -------------------------------------------- December 31, 2000 December 31, 1999 --------------------- --------------------- Annualized Trailing Annualized Trailing Fourth Twelve Fourth Twelve Quarter Month Quarter Month ---------- -------- ---------- -------- Protection One 15.0% 14.0% 14.7% 14.3% Protection One Europe 11.4% 12.2% 10.7% 9.5%
Our monitored services segment had a net decrease of 119,415 customers from December 31, 1999 to December 31, 2000. The number of customers decreased primarily because monitored services' customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace accounts lost through attrition. We expect that this trend will continue until the efforts being made to acquire new accounts at acceptable costs and reduce attrition become more successful than they have been to date. Until this trend has been reversed, net losses of customer accounts will materially and adversely affect monitored services' business, financial condition, results of operation and prospects.
Related Party Transactions
We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support, bill processing and human resources services. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses. In 2000 and 1999, ONEOK paid us $5.0 million and $5.6 million, net of what we owed ONEOK, for services.
At December 31, 2000, $44.0 million was outstanding under Protection One's senior credit facility with Westar Industries. In February 2001, the facility maturity date was extended to January 2, 2002 and in March 2001, Protection One requested a $40 million increase in the commitment under the facility pursuant to the terms of the facility.
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. Upon consummation of the PNM merger and the split-off, we will no longer consolidate Protection One's tax return with ours.
During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 million of these debt securities were transferred to Protection One. The balance of the bonds were sold to Protection One in March 2001. No gain or loss was recognized on these transactions.
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. Westar Industries has agreed to pay Protection One a portion of the net gain, if any, on a subsequent sale of the European businesses on a declining basis over the four years following the closing. 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.
We may acquire additional Protection One debt securities. The timing and terms of purchases, and the amount of debt actually purchased, will be based on market conditions and other factors. Purchases are expected to be made in the open market or through negotiated transactions. Because Protection One's debt currently trades at less than its carrying value, we would expect to realize an extraordinary gain on extinguishment of debt on any future purchases.
On February 28, 2001, Westar Industries converted a portion of a receivable owed by us into approximately 14.4 million shares of our common stock. See Note 2 of the Notes to Consolidated Financial Statements.
Market Risk Disclosure
Market Price Risks: We are exposed to market risk, including market changes, changes in commodity prices, equity instrument investment prices and interest rates.
Commodity Price Exposure: In 2000, we engaged in both trading and non- trading activities in our commodity price risk management activities. We traded electricity, gas and oil. We utilized a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps requiring payments (or receipt of payments) from counter-parties based on the differential between specified prices for the related commodity and futures traded on electricity, natural gas and oil.
We are involved in trading activities primarily to minimize risk from market fluctuations, capitalize on our market knowledge and enhance system reliability. We attempted to balance our physical and financial purchase and sale contracts in terms of quantities and contract terms. Net open positions existed or were established due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we had open positions, we were exposed to the risk that fluctuating market prices could adversely impact our financial position or results from operations. In 2001, we expect to trade coal, natural gas and oil fossil fuel types as well as electricity.
We manage and measure the exposure of our trading portfolio using a variance/covariance value-at-risk (VAR) model, which simulates forward price curves in the energy markets to estimate the size of future potential losses. The quantification of market risk using VAR methodologies provides a consistent measure of risk across diverse energy markets and products.
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. Our Risk Oversight Committee sets the VAR limit. The high, low and average VAR amounts for the year ended December 31, 2000, were $725,403, $36,559 and $269,217. We employ additional risk control mechanisms such as stress testing, daily loss limits, and commodity position limits. We expect to use the same VAR model and VAR limits in 2001.
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 counter-parties, product location (basis) differentials and other risks which management policy dictates. The counter-parties in our portfolio are primarily large energy marketers and major utility companies. The creditworthiness of our counter-parties could positively or negatively impact our overall exposure to credit risk. We maintain credit policies with regard to our counter-parties that, in management's view, minimize overall credit risk.
We are also exposed to commodity price changes outside of trading activities. We use derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of market prices. From 1999 to 2000, we experienced a 13% increase in the average price per MW of electricity purchased for utility operations. Actual purchased power market volatility was significantly greater than the average price increase indicates. If we were to have a similar increase from 2000 to 2001, given the amount of power purchased for utility operations during 2000, we would have an exposure of approximately $5.4 million of operating income. Due to the volatility of the power market, past prices can not be used to predict future prices.
We use a mix of various fuel types, including coal and natural gas, to operate our system which helps lessen our risk associated with any one fuel type. Natural gas prices increased significantly during 2000 throughout the nation. This increase impacted the cost of gas we used for generation as well as our cost of purchased power. From December 31, 1999 to December 31, 2000, we experienced a 45% increase in our average cost for natural gas purchased for utility operations, or an increase of $1.07 per MMBtu. The higher natural gas prices increased our total cost of gas purchased during 2000 by approximately $16.9 million although we decreased the quantity burned by 1.5 million MMBtu. If we were to have a similar increase from 2000 to 2001, we would have an exposure of approximately $24.4 million of operating income.
Based on MMBtu's of natural gas and fuel oil burned during 2000, we had exposure of approximately $6.8 million of operating income for a 10% change in average price paid per MMBtu. Actual natural gas market volatility was significantly greater than that indicated by the average price increase. Due to the volatility of natural gas prices, past prices can not be used to predict future prices.
During the first quarter of 2001, spot market prices for western coal markets increased significantly. This increase will impact the fuel contracts currently in place for a portion of our 2001 anticipated coal needs at our La Cygne Generating Station, increasing our coal commodity price market risk. We believe that 2001 spot market purchases will be at higher rates than those experienced during 2000.
In an effort to mitigate fuel commodity price market risk, we use hedging arrangements to minimize 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 we enter into.
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 individual fuel's availability, price, deliverability, unit outages and nuclear refueling. Our customer's electricity usage could also vary dramatically year to year based on the weather or other factors.
Financial Hedging Exposure: We also use financial 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.
Decline in Equity Price Risk: During 2000, our balance in marketable securities declined approximately $173.2 million from December 31, 1999, due to the sale of a significant portion of our marketable security portfolio. We do not expect to be materially impacted by changes in the market prices of our remaining investments.
Interest Rate Exposure: We have approximately $156.9 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2000. Our weighted average interest rate increased from 6.96% at December 31, 1999 to 8.11% at December 31, 2000. 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 annual basis by approximately $1.6 million after tax.
Foreign Currency Exchange Rates: We have foreign operations with functional currencies other than the United States dollar. As of December 31, 2000, the unrealized loss on currency translation, presented as a separate component of shareholders' equity and reported within other comprehensive income was approximately $9.4 million pretax. A 10% change in the currency exchange rates would have an immaterial effect on other comprehensive income.
New Accounting Pronouncements
In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
We adopted SFAS 133 on January 1, 2001. We have evaluated our commodity contracts, financial instruments and other contracts and have determined that we have derivative instruments which will be marked to market through earnings in accordance with SFAS 133. We will not designate any derivatives as hedges. We estimate that the effect on our financial statements of adopting SFAS 133 on January 1, 2001, will be to increase pre-tax earnings for the first quarter of 2001 by approximately $31 million. Accounting for derivatives under SFAS 133 may increase volatility in future earnings.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - --------------------------------------------------------------------
Information relating to market risk disclosure is set forth in Other Information of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included herein.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ----------------------------------------------------
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented:
I, III, IV, and V.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Western Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, cash flows, and shareholders' equity for each of the three years in the period ended December 31, 2000. These financial statements and the schedule referred to below are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements and this schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits 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, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. Schedule II - Valuation and Qualifying Accounts is presented for purposes of complying with the Securities and Exchange Commission rules and is not part of the basic financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Kansas City, Missouri, March 9, 2001
WESTERN RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (In Thousands)
December 31, ------------------------ 2000 1999 ---------- ----------- ASSETS CURRENT ASSETS: Cash and cash equivalents............................ $ 8,762 $ 11,040 Restricted cash...................................... 22,205 15,962 Accounts receivable (net)............................ 152,165 229,200 Inventories and supplies (net)....................... 101,303 112,392 Marketable securities................................ 3,946 177,128 Energy trading contracts............................. 185,364 16,370 Prepaid expenses and other........................... 40,503 40,876 ---------- ---------- Total Current Assets................................ 514,248 602,968 ---------- ----------
PROPERTY, PLANT AND EQUIPMENT (NET)................... 3,993,438 3,889,444 ---------- ----------
OTHER ASSETS: Restricted cash...................................... 35,878 - Investment in ONEOK.................................. 591,173 590,109 Customer accounts (net).............................. 1,005,505 1,122,585 Goodwill (net)....................................... 976,102 1,057,041 Regulatory assets.................................... 327,350 366,004 Other................................................ 323,514 361,741 ---------- ---------- Total Other Assets.................................. 3,259,522 3,497,480 ---------- ----------
TOTAL ASSETS.......................................... $7,767,208 $7,989,892 ========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt................. $ 41,825 $ 111,667 Short-term debt...................................... 35,000 705,421 Accounts payable..................................... 177,067 132,834 Accrued liabilities.................................. 207,329 226,786 Accrued income taxes................................. 53,834 40,328 Deferred security revenues........................... 73,585 61,148 Energy trading contracts............................. 191,673 15,182 Other................................................ 34,187 57,829 ---------- ---------- Total Current Liabilities........................... 814,500 1,351,195 ---------- ----------
LONG-TERM LIABILITIES: Long-term debt (net)................................. 3,237,849 2,883,066 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company subordinated debentures.............. 220,000 220,000 Deferred income taxes and investment tax credits..... 919,807 976,135 Minority interests................................... 184,591 192,734 Deferred gain from sale-leaseback.................... 186,294 198,123 Other................................................ 272,747 279,451 ---------- ---------- Total Long-term Liabilities......................... 5,021,288 4,749,509 ---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 14)
SHAREHOLDERS' EQUITY: Cumulative preferred stock........................... 24,858 24,858 Common stock, par value $5 per share, authorized 150,000,000 shares, outstanding 70,082,314 and 67,401,657 shares, respectively..................... 350,412 341,508 Paid-in capital...................................... 850,100 820,945 Retained earnings.................................... 714,454 679,880 Accumulated other comprehensive income (loss) (net).. (8,404) 37,788 Treasury stock, at cost, 0 and 900,000 shares, respectively....................................... - (15,791) ---------- ---------- Total Shareholders' Equity.......................... 1,931,420 1,889,188 ---------- ----------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY.............. $7,767,208 $7,989,892 ========== ==========
The Notes to Consolidated Financial Statements are an integral part of these statements.
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
The Notes to Consolidated Financial Statements are an integral part of these statements.
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Thousands)
The Notes to Consolidated Financial Statements are an integral part of these statements.
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands)
The Notes to Consolidated Financial Statements are an integral part of these statements.
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands)
The Notes to Consolidated Financial Statements are an integral part of these statements.
WESTERN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business: Western Resources, Inc. (Western Resources, the company) is a publicly traded consumer services company. The company's primary business activities are providing electric generation, transmission and distribution services to approximately 636,000 customers in Kansas and providing monitored security services to approximately 1.5 million customers in North America and Europe. Rate regulated electric service is provided by KPL, a division of the company, and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary. Monitored security services are provided by Protection One, Inc., a publicly traded, approximately 85%-owned subsidiary, and other wholly owned subsidiaries collectively referred to as Protection One Europe. In addition, through the company's 45% ownership interest in ONEOK, Inc., natural gas transmission and distribution services are provided to approximately 1.4 million customers in Oklahoma and Kansas. Westar Industries, Inc., the company's wholly owned subsidiary, owns the company's interests in Protection One, Protection One Europe, ONEOK and other non-utility businesses.
Principles of Consolidation: The company prepares its financial statements in conformity with accounting principles generally accepted in the United States. The accompanying Consolidated Financial Statements include the accounts of Western Resources and its wholly owned and majority owned subsidiaries. All material intercompany accounts and transactions have been eliminated. Common stock investments that are not majority owned are accounted for using the equity method when the company's investment allows it the ability to exert significant influence.
Regulatory Accounting: The company currently applies accounting standards for its rate regulated electric business that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS 71) and, accordingly, has recorded regulatory assets and liabilities when required by a regulatory order or when it is probable, based on regulatory precedent, that future rates will allow for recovery of a regulatory asset.
Use of Management's Estimates: The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents: The company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents.
Restricted Cash: Restricted cash consists of cash used to collateralize letters of credit and cash held in escrow.
Accounts Receivable: Receivables, which consist primarily of trade accounts receivable, were reduced by allowances for doubtful accounts of $45.8 million at December 31, 2000 and $35.8 million at December 31, 1999.
Available-for-sale Securities: The company classifies marketable equity and debt securities accounted for under the cost method as available-for-sale. These securities are reported at fair value based on quoted market prices. Cumulative, temporary unrealized gains and losses, net of the related tax effect, are reported as a separate component of shareholders' equity until realized. Current temporary changes in unrealized gains and losses are reported as a component of other comprehensive income. Realized gains and losses are included in earnings and are derived using the specific identification method.
The following table summarizes the company's investments in marketable securities as of December 31:
Gross Unrealized ---------------- Cost Gains Losses Fair Value -------- ------- --------- ---------- (In Thousands) 2000: Equity securities............ $ 6,690 $ - $ (2,744) $ 3,946 Debt securities.............. - - - - -------- ------- -------- -------- Total...................... $ 6,690 $ - $ (2,744) $ 3,946 ======== ======= ======== ========
1999: Equity securities............ $ 43,124 $70,407 $ (1,628) $111,903 Debt securities.............. 65,225 - - 65,225 -------- ------- -------- -------- Total...................... $108,349 $70,407 $ (1,628) $177,128 ======== ======= ======== ========
Proceeds from the sales of equity and debt securities were $218.6 million in 2000 and $73.5 million in 1999. The gross realized gains from sales of equity and debt investments were $116.0 million in 2000 and $12.6 million in 1999. The gross realized losses from sales of equity and debt investments were $1.0 million in 2000 and $38.8 million in 1999.
Energy Trading Contracts: The company is involved in system hedging and trading activities primarily to minimize risk from commodity market fluctuations, capitalize on its market knowledge and enhance system reliability. In these activities, the company utilizes a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps requiring payments (or receipt of payments) from counter-parties based on the differential between specified prices for the related commodity, and futures traded on electricity and natural gas.
The company accounts for transactions on either a settlement basis or using the mark-to-market method of accounting. On a settlement basis, the company recognizes the gains or losses on system hedging transactions as the power is delivered. Under the mark-to-market method of accounting, trading transactions are shown at fair value in the consolidated balance sheets as energy trading contracts assets - current and energy trading contracts liabilities-current. Long term energy trading contract assets and liabilities are included in other long term assets and other long term liabilities, respectively. The company reflects changes in fair value resulting in unrealized gains and losses from these transactions in energy sales. The company records the revenues and costs for all transactions in its consolidated statements of income when the contracts are settled. The company recognizes revenues in energy sales; costs are recorded in energy cost of sales.
The company values contracts in the trading portfolio using end-of-the- period market prices, utilizing the following factors (as applicable):
- closing exchange prices (that is, closing prices for standardized electricity products traded on an organized exchange such as the New York Mercantile Exchange); - broker dealer and over-the-counter price quotations;
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, supervision, general and administrative costs 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 7.39% in 2000, 6.00% in 1999 and 6.00% in 1998. The cost of additions to utility plant and replacement units of property are capitalized. Interest capitalized into construction in progress was $9.4 million in 2000, $4.4 million in 1999 and $1.9 million in 1998.
Maintenance costs and replacement of minor items of property are charged to expense as incurred. Incremental costs incurred during scheduled Wolf Creek Generating Station refueling and maintenance outages are deferred and amortized monthly over the unit's operating cycle, normally about 18 months. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation.
In accordance with regulatory decisions made by the Kansas Corporation Commission (KCC), the acquisition premium of approximately $801 million resulting from the acquisition of KGE in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization totaled $108.2 million as of December 31, 2000 and $88.1 million as of December 31, 1999.
Depreciation: Utility plant is depreciated on the straight-line method at rates approved by regulatory authorities. Utility plant is depreciated on an average annual composite basis using group rates that approximated 2.99% during 2000, 2.92% during 1999 and 2.88% during 1998. Nonutility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. The company periodically evaluates its depreciation rates considering the past and expected future experience in the operation of its facilities.
Inventories and Supplies: Inventories and supplies for the company's utility business are stated at average cost. Monitored services' inventories, comprised of alarm systems and parts, are stated at the lower of average cost or market.
Nuclear Fuel: The cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as an asset at original cost and is amortized to cost of sales based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $18.6 million at December 31, 2000 and $29.3 million at December 31, 1999.
Customer Accounts: Customer accounts are stated at cost. 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 and Protection One Europe historically amortized most customer accounts by using the straight-line method over a ten-year life. The choice of an amortization life was based on estimates and judgments about the amounts and timing of expected future revenues from these assets and average customer account life. Selected periods were determined because, in Protection One's and Protection One Europe's opinion, they would adequately match amortization cost with anticipated revenue.
Protection One and Protection One Europe conducted a comprehensive review of their amortization policy during the third quarter of 1999. This review was performed specifically to evaluate the historic amortization policy in light of the inherent declining revenue curve over the life of a pool of customer accounts and Protection One's historical attrition experience. After completing the review, Protection One identified three distinct pools, each of which has distinct attributes that effect differing attrition characteristics. The pools corresponded to Protection One's North America, Multifamily and Europe business segments. For the North America and Europe pools, the analyzed data indicated that Protection One can expect attrition to be greatest in years one through five of asset life and that a change from a straight-line to a declining balance (accelerated) method would more closely match future amortization cost with the estimated revenue stream from these assets. Protection One elected to change to that method, except for accounts acquired in the Westinghouse acquisition which are utilizing an accelerated method. No change was made in the method used for the Multifamily pool.
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:
Pool Method ------------------------------------------------------------------------ North America Acquired Westinghouse customers Eight-year 120% declining balance Other customers Ten-year 130% declining balance Europe Ten-year 125% declining balance Multifamily Ten-year straight-line
Adoption of the declining balance method effectively shortens the estimated expected average customer life for these customer pools, and does so in a way that does not make it possible to distinguish the effect of a change in method (straight-line to declining balance) from the change in estimated lives. In such cases, generally accepted accounting principles require that the effect of such a change be recognized in operations in the period of the change, rather than as a cumulative effect of a change in accounting principle. Protection One changed to the declining balance method in the third quarter of 1999 for Europe customers and the North America customers which had been amortized on a straight-line basis. Accordingly, the effect of the change in accounting principle increased Protection One's amortization expense reported in the third quarter of 1999 by approximately $40 million. Accumulated amortization would have been approximately $34 million higher through the end of the second quarter of 1999 if the declining balance method had historically been used.
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.
Goodwill has been recorded in business acquisitions where the principal asset acquired was the recurring revenues from the acquired customer base. For purposes of the impairment analysis, goodwill has been considered directly related to the acquired customers.
Due to the high level of customer attrition experienced in 2000 and 1999, the decline in market value of Protection One's publicly traded equity and debt securities and because of recurring losses, Protection One and Protection One Europe performed an impairment test on their customer account assets and goodwill in both 2000 and 1999. These tests indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill.
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 estimates of goodwill life from 40 years to 20 years as of January 1, 2000. After that date, remaining goodwill, net of accumulated amortization, is being amortized over its remaining useful life based on a 20-year life. As a result of this change in estimate, goodwill amortization expense for the year ended December 31, 2000 increased by approximately $33.0 million.
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, 2000.
Amortization expense was $61.4 million, $31.6 million and $22.5 million for the years ended December 31, 2000, 1999 and 1998. Accumulated amortization was $118.6 million and $59.3 million at December 31, 2000 and 1999.
The Financial Accounting Standards Board (FASB) issued an exposure draft on February 14, 2001 which, if adopted as proposed, would establish a new accounting standard for the treatment of goodwill in a business combination. The new standard would continue to require recognition of goodwill as an asset in a business combination but would not permit amortization as currently required by APB Opinion No. 17, "Intangible Assets." The new standard would require that goodwill be separately tested for impairment using a fair-value based approach as opposed to an undiscounted cash flow approach which is required under current accounting standards. If goodwill is found to be impaired, the company would be required to record a non-cash charge against income. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds the fair value. Goodwill would no longer be amortized on a current basis as is required under current accounting standards. The exposure draft contemplates this standard to become effective on July 1, 2001, although this effective date is not certain. Furthermore, the proposed standard could be modified prior to its adoption.
If the new standard is adopted, any subsequent impairment test on the company's customer accounts would be performed on the customer accounts alone rather than in conjunction with goodwill utilizing an undiscounted cash flow test pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of."
At December 31, 2000, the company had $976 million in goodwill attributable to acquisitions of businesses and $1,006 million for monitored services' customer accounts. These intangible assets together represented 25.5% of the book value of the company's total assets. The company recorded approximately $61.4 million in goodwill amortization expense in 2000. If the new standard becomes effective July 1, 2001 as proposed, the company believes it is probable that it would be required to record a non-cash impairment charge. The company cannot determine the amount at this time, but it believes the amount would be material and could be a substantial portion of its intangible assets. This impairment charge would have a material adverse effect on the company's operating results in the period recorded.
Regulatory Assets and Liabilities: Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. The company has recorded these regulatory assets in accordance with SFAS 71. If the company were required to terminate application of that statement for all of its regulated operations, the company would have to record the amounts of all regulatory assets and liabilities in its Consolidated Statements of Income at that time. The company's earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets reflected in the Consolidated Financial Statements are as follows:
As of December 31, ------------------ 2000 1999 -------- -------- (In Thousands) Recoverable income taxes............... $187,308 $218,239 Debt issuance costs.................... 63,263 68,239 Deferred employee benefit costs........ 36,251 36,251 Deferred plant costs................... 29,921 30,306 Other regulatory assets................ 10,607 12,969 -------- -------- Total regulatory assets.............. $327,350 $366,004 ======== ========
- Recoverable income taxes: Recoverable income taxes represent amounts due from customers for accelerated tax benefits which have been previously flowed through to customers and are expected to be recovered in the future as the accelerated tax benefits reverse.
- 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 over the term of the associated debt.
- Deferred employee benefit costs: Deferred employee benefit costs represent costs to be recovered by income generated through the company's Affordable Housing Tax Credit (AHTC) investment program as authorized by the KCC.
- Deferred plant costs: Costs related to the Wolf Creek nuclear generating facility.
The company expects to recover all of the above regulatory assets in rates charged to customers. A return is allowed on deferred plant costs and coal contract settlement costs and approximately $18.0 million of debt issuance costs.
Minority Interests: Minority interests represent the minority shareholders' proportionate share of the shareholders' equity and net loss of Protection One.
Revenue Recognition
Energy Sales Recognition: Energy sales are recognized as services are rendered and include estimated amounts for energy delivered but unbilled at the end of each year. Unbilled sales are recorded as a component of accounts receivable (net) and amounted to $44 million at December 31, 1999. During 2000, the company sold its energy related accounts receivable, including amounts related to unbilled sales.
Monitored Services Sales Recognition: Monitored services sales are recognized when security services are provided. Installation revenue, sales revenues on equipment upgrades and direct costs of installations and sales are deferred for residential customers with service contracts. For commercial customers and national account customers, revenue recognition is dependent upon each specific customer contract. In instances when the company sells the equipment outright, revenues and costs are recognized in the period incurred. In cases where there is no outright sale, revenues and direct costs are deferred and amortized.
Deferred installation revenues and system sales revenues will be recognized over the expected useful life of the customer, utilizing a 130% declining balance. Deferred costs in excess of deferred revenues will be recognized over the contract life. To the extent deferred costs are less than deferred revenues, such costs are recognized over the customers' estimated useful life, utilizing a 130% declining balance.
Deferred revenues also result from customers who are billed for monitoring, extended service protection and patrol and response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis.
Income Taxes: Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits.
Foreign Currency Translation: The assets and liabilities of the company's foreign operations are generally translated into U.S. dollars at current exchange rates and revenues and expenses are translated at average exchange rates for the year.
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 the Consolidated Balance Sheets at December 31:
2000 1999 ------- ------- (In Millions) Cash surrender value of policies (a).... $ 705.4 $ 642.4 Borrowings against policies............. (665.9) (608.3) ------- ------- COLI (net).............................. $ 39.5 $ 34.1 ======= =======
(a) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 2000 and 1999.
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 $0.9 million in 2000, $1.4 million in 1999 and $13.7 million in 1998.
Cumulative Effect of Accounting Change: The company adopted Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB 101) in the fourth quarter of 2000 which had a retroactive effective date of January 1, 2000. The impact of this accounting change generally requires deferral of certain monitored 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. Historically, Protection One acquired a majority of its customers by acquisition or through an independent dealer program for its North American operations. Dealers billed and retained any installation revenues. In 2000, Protection One began an internal sales program. Because of these factors the impact of adopting SAB 101 for Protection One was not significant. Protection One Europe has a larger concentration of commercial customers where installation revenues and related costs had previously been recognized.
The cumulative effect of the change in accounting principle was approximately $3.8 million, net of tax benefits of $1.1 million and is related to changes in revenue recognition at Protection One Europe. Prior to the adoption of SAB 101, Protection One Europe recognized installation revenues and related expenses upon completion of the installation. Pro forma amounts and amounts per share, assuming the change in accounting principle was applied retroactively are as follows:
New Accounting Pronouncements: In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
The company adopted SFAS 133 on January 1, 2001. The company has evaluated its commodity contracts, financial instruments and other contracts and determined that certain commodity contracts are derivative instruments. Under current GAAP, these contracts qualify as hedges. However, under SFAS 133, these contracts will not qualify as hedges. Accordingly, the instruments will be marked to market through earnings. The company estimates that the effect on its financial statements of adopting SFAS 133 on January 1, 2001, will be to increase pre-tax earnings for the first quarter of 2001 by approximately $31 million. Accounting for derivatives under SFAS 133 may increase volatility in future earnings.
Supplemental Cash Flow Information: Cash paid for interest and income taxes for each of the years ended December 31, are as follows:
2000 1999 1998 -------- -------- -------- (In Thousands) Interest on financing activities (net of amount capitalized)......... $310,345 $298,802 $220,848 Income taxes.......................... 28,751 784 47,196
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES
On November 8, 2000, the company entered into an agreement under which Public Service Company of New Mexico (PNM) will acquire the electric utility businesses of the company in a stock-for-stock transaction. Under the terms of the agreement, both the company and PNM will become subsidiaries of a new holding company. Immediately prior to the consummation of this combination, the company will split-off its remaining interest in Westar Industries to its shareholders.
Westar Industries has filed a registration statement with the Securities and Exchange Commission (SEC) covering the proposed sale of a portion of its common stock through the exercise of non-transferable rights proposed to be distributed by Westar Industries to the company's shareholders.
The company and Westar Industries entered into an Asset Allocation and Separation Agreement at the same time the company entered into the merger agreement with PNM. Among other things, this agreement permits a receivable owed by the company to Westar Industries to be converted into certain securities of the company. At the closing of the merger, any of these securities then owned by Westar Industries will be converted into securities of PNM or the holding company to be formed by PNM.
On February 28, 2001, Westar Industries converted $350 million of the receivable into approximately 14.4 million shares of the company's common stock pursuant to the Asset Allocation and Separation Agreement. These shares represent approximately 16.9% of the company's outstanding common stock including these shares in outstanding shares. There are no voting rights with respect to these shares as long as Westar Industries is a majority owned subsidiary of the company.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings: On November 27, 2000, the company and KGE filed applications with the KCC for a change in retail rates which included a cost allocation study and separate cost of service studies for the company's KPL division and KGE. The company requested an annual rate increase totaling approximately $151 million. The company and KGE also provided revenue requirements on a combined company basis on December 28, 2000. The company anticipates a ruling by the KCC in July 2001 but is unable to predict its outcome.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint with the Federal Energy Regulatory Commission (FERC) against the company alleging improper affiliate transactions between the company's KPL division and KGE, a wholly owned subsidiary of the company. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. A hearing on the case was held at FERC on October 11 and 12, 2000 and on November 9, 2000 a FERC administrative law judge ruled in favor of the company that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, the company filed a brief opposing the City's position. The company anticipates a decision by FERC in the second quarter of 2001.
4. SALE OF ACCOUNTS RECEIVABLE
On July 28, 2000, the company and KGE entered into an agreement to sell, on an ongoing basis, all of their accounts receivable arising from the sale of electricity, to WR Receivables Corporation, a special purpose entity wholly owned by the company. The agreement expires on July 26, 2001, and is annually renewable upon agreement by both parties. The special purpose entity has sold and, subject to certain conditions, may from time to time sell, up to $125 million (and upon request, subject to certain conditions, up to $175 million) of an undivided fractional ownership interest in the pool of receivables to a third-party, multi-seller receivables funding entity affiliated with a lender. The company's retained interests in the receivables sold are recorded at cost which approximates fair value. The company has received net proceeds of $115.0 million as of December 31, 2000.
5. SHORT-TERM DEBT
The company has an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by first mortgage bonds of the company and KGE and matures on March 17, 2003. The company also has arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $12.0 million. As of December 31, 2000, borrowings on these facilities were $35.0 million.
The agreements provide the company with the ability to borrow at different market-based interest rates. The company pays commitment or facility fees in support of these lines of credit. Under the terms of the agreements, the company is required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. The company is in compliance with all restrictions.
Information regarding the company's short-term borrowings, comprised of borrowings under the credit agreements, bank loans and commercial paper, is as follows:
As of December 31, ---------------------- 2000 1999 --------- ----------- (Dollars in Thousands) Borrowings outstanding at year end: Credit agreement.................... $ 35,000 $ 50,000 Bank loans.......................... - 120,000 Commercial paper notes.............. - 535,421 -------- ---------- Total.............................. $ 35,000 $ 705,421 ======== ==========
Weighted average interest rate on debt outstanding at year end (including fees).................... 8.11% 6.96%
Weighted average short-term debt outstanding during the year......... $402,845 $ 455,184
Weighted daily average interest rates during the year (including fees).................... 7.92% 5.76%
Unused lines of credit supporting commercial paper notes.................. $ - $1,021,000
The company's interest expense on short-term debt and other was $63.1 million in 2000, $57.7 million in 1999 and $55.3 million in 1998.
6. LONG-TERM DEBT
Long-term debt outstanding is as follows at December 31:
2000 1999 ---------- ---------- (In Thousands) Western Resources - ----------------- First mortgage bond series: 8 7/8% due 2000.................................. $ - $ 75,000 7 1/4% due 2002.................................. 100,000 100,000 8 1/2% due 2022.................................. 125,000 125,000 7.65% due 2023................................... 100,000 100,000 ---------- ---------- 325,000 400,000 ---------- ----------
Pollution control bond series: Variable due 2032, 4.70% at December 31, 2000.... 45,000 45,000 Variable due 2032, 4.62% at December 31, 2000.... 30,500 30,500 6% due 2033...................................... 58,410 58,420 ---------- ---------- 133,910 133,920 ---------- ----------
6 7/8% unsecured senior notes due 2004........... 370,000 370,000 7 1/8% unsecured senior notes due 2009........... 150,000 150,000 6.80% unsecured senior notes due 2018............ 28,977 29,783 6.25% unsecured senior notes due 2018, putable/callable 2003.......................... 400,000 400,000 Senior secured term loan......................... 600,000 - Other long-term agreements....................... 16,889 21,895 ---------- ---------- 1,565,866 971,678 ---------- ----------
KGE - --- First mortgage bond series: 7.60% due 2003................................... 135,000 135,000 6 1/2% due 2005.................................. 65,000 65,000 6.20% due 2006................................... 100,000 100,000 ---------- ---------- 300,000 300,000 ---------- ---------- Pollution control bond series: 5.10% due 2023................................... 13,623 13,653 Variable due 2027, 4.60% at December 31, 2000.... 21,940 21,940 7.0% due 2031.................................... 327,500 327,500 Variable due 2032, 4.60% at December 31, 2000.... 14,500 14,500 Variable due 2032, 4.60% at December 31, 2000.... 10,000 10,000 ---------- ---------- 387,563 387,593 ---------- ----------
Protection One - -------------- Convertible senior subordinated notes due 2003, fixed rate 6.75%..................... 23,785 53,950 Senior subordinated discount notes due 2005, effective rate of 11.8%........................ 42,887 87,038 Senior unsecured notes due 2005, fixed rate 7.375%.............................. 204,650 250,000 Senior subordinated notes due 2009, fixed rate 8.125% (1).......................... 255,740 341,415 Other............................................ 267 2,033 ---------- ---------- 527,329 734,436 ---------- ---------- Protection One Europe - --------------------- CET recourse financing agreements, average effective rate 15%............................. 33,512 60,838
Unamortized debt premium........................... 13,541 13,726
Less: Unamortized debt discount........................ (7,047) (7,458) Long-term debt due within one year............... (41,825) (111,667) ---------- ---------- Long-term debt (net)............................. $3,237,849 $2,883,066 ========== ==========
(1) The rate is currently 8.625% and will continue at that rate until an exchange offer related to the offering is completed.
Debt discount and expenses are being amortized over the remaining lives of each issue.
The amount of the company'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. First mortgage bonds are secured by the utility assets of the company and KGE. Amounts of additional bonds which may be issued are subject to property, earnings and certain restrictive provisions of each mortgage.
The company's unsecured debt represents general obligations that are not secured by any of the company's properties or assets. Any unsecured debt will be subordinated to all secured debt of the company, including the first mortgage bonds. The notes are structurally subordinated to all secured and unsecured debt of the company's subsidiaries.
On June 28, 2000, the company entered into a $600 million, multi-year term loan that replaced two revolving credit facilities which matured on June 30, 2000. The net proceeds of the term loan were used to retire short-term debt. The term loan is secured by first mortgage bonds of the company and KGE and has a maturity date of March 17, 2003.
Maturities of the term loan through March 17, 2003, are as follows:
Principal Amount Year (In Thousands) ------------------------------------- 2001...................... $ 9,000 2002...................... 6,000 2003...................... 585,000 -------- $600,000
The terms of the loan contain requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. The company is in compliance with all of these requirements.
Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. The weighted average interest rate, including amortization of fees, on the term loan for the year ending December 31, 2000, was 10.28%.
In 1998, Protection One issued $350 million of Unsecured Senior Subordinated Notes. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price. Protection One did not complete a required exchange offer during 1999. As a result, the interest rate on these notes has been 8.625% since June 1999. If the exchange offer is completed, the interest rate will revert back to 8.125%. Interest on these notes is payable semi-annually on January 15 and July 15.
In 1998, Protection One issued $250 million of Senior Unsecured Notes. Interest is payable semi-annually on February 15 and August 15. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price.
In 1995, Protection One issued $166 million of Unsecured Senior Subordinated Discount Notes with a fixed interest rate of 13.625%. Interest payments began in 1999 and are payable semi-annually on June 30 and December 31. In connection with the acquisition of Protection One in 1997, these notes were restated to fair value reflecting a current market yield of approximately 6.4% through June 30, 2000, the first full call date of the notes. Since the notes were not called on that date the current market yield was adjusted to 11.8% as of July 1, 2000. The 1997 revaluation resulted in bond premium being recorded to reflect the increase in value of the notes as a result of the decline in interest rates since the note issuance. This revaluation had no impact on the expected cash flow to existing noteholders. As of June 30, 2000, the notes became redeemable at Protection One's option, at a specified redemption price.
In 1998, Protection One redeemed unsecured senior subordinated discount notes with a book value of $69.4 million and recorded an extraordinary gain on the extinguishment of $1.6 million, net of tax.
In 1996, Protection One issued $103.5 million of Convertible Senior Subordinated Notes. Interest is payable semi-annually on March 15 and September 15. The notes are convertible at any time at a conversion price of $11.19 per share. The notes are redeemable, at Protection One's option, at a specified redemption price, beginning September 19, 1999.
In 1999, Westar Industries purchased Protection One bonds on the open market at amounts less than the carrying amount of the debt. The company recognized an extraordinary gain of $13.4 million, net of tax, at December 31, 1999, related to the retirement of this debt.
During 2000, Westar Industries purchased various issues of Protection One bonds on the open market at amounts less than the carrying amount of the debt. The company recognized an extraordinary gain of $49.2 million, net of tax, at December 31, 2000, related to the retirement of this debt.
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.
Maturities of long-term debt through 2005 are as follows:
Principal Amount Year (In Thousands) --------------------------------- 2001................ $ 41,825 2002................ 116,705 2003................ 747,207 2004................ 370,617 2005................ 313,007 Thereafter.......... 1,683,819 ---------- $3,273,180
The company's interest expense on long-term debt was $226.4 million in 2000, $236.4 million in 1999 and $170.9 million in 1998.
Protection One's debt instruments contain financial and operating covenants which may restrict its ability to incur additional debt, pay dividends, make loans or advances and sell assets. At December 31, 2000, Protection One was in compliance with all financial covenants governing its debt securities.
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.
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107 "Disclosures about Fair Value of Financial Instruments."
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 below. The decommissioning trust is recorded at fair value and is based on the quoted market prices at December 31, 2000 and 1999. The fair value of fixed-rate debt and other mandatorily redeemable securities is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The estimated fair values of contracts related to commodities have been determined using quoted market prices of the same or similar securities.
The recorded amounts of accounts receivable and other current financial instruments approximate fair value.
The fair value estimates presented herein are based on information available at December 31, 2000 and 1999. These fair value estimates have not been comprehensively revalued for the purpose of these financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein.
The carrying values and estimated fair values of the company's financial instruments are as follows:
Carrying Value Fair Value ---------------------- ---------------------- As of December 31, ---------------------------------------------- 2000 1999 2000 1999 ---------- ---------- ---------- ---------- (In Thousands)
Decommissioning trust.... $ 64,222 $ 58,286 $ 64,222 $ 58,286 Fixed-rate debt, net of current maturities...... 3,109,415 2,743,057 2,809,711 2,350,880 Other mandatorily redeemable securities... 220,000 220,000 182,232 187,950
The tables below present the estimated fair value of contracts not settled at December 31, 2000.
The notional volumes and estimated fair values of the company's forward contracts and options for electricity positions are as follows at December 31:
2000 1999 ---------------------- ---------------------- Notional Notional Volumes Estimated Volumes Estimated (MWH's) Fair Value (MWH's) Fair Value --------- ---------- --------- ---------- (Dollars in Thousands) Forward contracts: Purchased................ 3,581,500 $264,488 1,137,600 $33,021 Sold..................... 3,713,248 269,731 1,088,800 32,395
Options: Purchased................ 647,600 $ 12,606 944,800 $ 5,524 Sold..................... 387,200 11,976 754,200 8,458
The notional volumes and estimated fair values of the company's forward contract and options for gas positions are as follows at December 31:
2000 1999 ----------------------- ----------------------- Notional Notional Volumes Estimated Volumes Estimated (MMBtu's) Fair Value (MMBtu's) Fair Value ---------- ---------- ---------- ---------- (Dollars in Thousands) Forward contracts: Purchased................ 73,859,179 $283,453 13,010,000 $31,002 Sold..................... 50,614,417 174,441 500,000 1,108
Options: Purchased................ 39,171,500 $ 21,887 6,000,000 $ 971 Sold..................... 30,140,000 21,196 4,000,000 615
Under mark-to-market accounting, energy trading contracts with third parties are reflected at fair market value, net of reserves, with resulting unrealized gains and losses recorded as energy trading contract assets and liabilities. These assets and liabilities are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. These changes are recognized as revenues in the consolidated statements of income in the period the changes occur. As of December 31, 2000, the company had gross mark-to-market gains (asset position) and losses (liability position) on these energy trading contracts as follows:
2000 1999 -------- ------- (In Thousands) Current Assets - energy trading contracts...... $185,364 $16,370 Other Assets - other........................... 15,883 - -------- ------- $201,247 $16,370 -------- -------
Current Liabilities - energy trading contracts. $191,673 $15,182 Long-term liabilities - other.................. 1,096 - -------- ------- $192,769 $15,182 -------- ------- Net mark-to-market gains..................... $ 8,478 $ 1,188 ======== =======
These net mark-to-market gains have been recognized in revenue. Included within these assets and liabilities is an unrealized gain of $31 million which will be recognized through revenue in 2001 as a cumulative effect of an accounting change upon adoption of SFAS 133.
8. MONITORED SERVICES BUSINESS
In 1999, Protection One sold the assets which comprised its Mobile Services Group. Cash proceeds of this sale approximated $20 million and Protection One recorded a pre-tax gain of approximately $17 million. This gain is reflected in other income (expense) - other on the statement of income.
Protection One acquired a significant number of security companies in 1998. All companies acquired have been accounted for using the purchase method. The principal assets acquired in the acquisitions are customer accounts. The excess of the purchase price over the estimated fair value of the net assets acquired is recorded as goodwill. The results of operations of each acquisition have been included in the consolidated results of operations of Protection One from the date of the acquisition.
The following table presents the unaudited pro forma financial information considering Protection One's monitored services acquisitions in 1998. The table assumes acquisitions in 1998 occurred as of January 1, 1998.
Year Ended December 31, 1998 ----------- (Unaudited) (In Thousands, Except Per Share Data) ----------------------
Sales......................................... $2,175,089 Earnings available for common stock........... $21,449 Earnings per share............................ $0.33
The unaudited pro forma financial information is not necessarily indicative of the results of operations had the entities been combined for the entire period nor do they purport to be indicative of results which will be obtained in the future.
9. MARKETABLE SECURITIES
During the fourth quarter of 1999, the company decided to sell its remaining marketable security investments in paging industry companies. These securities were classified as available-for-sale; therefore, changes in market value were historically reported as a component of other comprehensive income.
The market value for these securities declined during the last six to nine months of 1999. The company determined that the decline in value of these securities was other than temporary and a charge to earnings for the decline in value was required at December 31, 1999. Therefore, a non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in the accompanying Consolidated Statements of Income.
In February 2000, a paging company whose securities were included in the securities discussed in the paragraph above at December 31, 1999, made an announcement that significantly increased the market value of paging company securities generally in the public markets. During the first quarter of 2000, the remainder of these paging securities were sold and a gain of $24.9 million was realized.
During 2000, the company sold its equity investment in a gas compression company and realized a pre-tax gain of $91.1 million.
1O. CUSTOMER ACCOUNTS
The following is a rollforward of the investment in customer accounts (at cost) for the following years:
December 31, ----------------------- 2000 1999 --------- --------- (In Thousands) Beginning customer accounts, net.............. $1,122,585 $1,009,084 Acquisition of customer accounts.............. 54,993 337,464 Amortization of customer accounts............. (163,297) (185,974) Non-cash charges against purchase holdbacks...................... (8,776) (37,989) ---------- ---------- Ending customer accounts, net................. $1,005,505 $1,122,585 ========== ==========
Accumulated amortization of the investment in customer accounts at December 31, 2000 and 1999 was $493.4 million and $330.7 million.
11. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD
The company's investments which are accounted for by the equity method are as follows:
(a) The company also received approximately $40 million and $41 million of preferred and common dividends in 2000 and 1999. (b) Investment is aggregated. Individual investments are not material. Based on an order received by the KCC, equity earnings from these investments are used to offset costs associated with post-retirement and post- employment benefits offered to the company's employees. (c) The company sold this investment on December 15, 2000. (d) Investment is aggregated. Individual investments are not material.
The following summarized unaudited financial information for the company's investment in ONEOK is as follows:
As of December 31, ---------------------- 2000 1999 ---------- ---------- (In Thousands) Balance Sheet: Current assets.................... $3,324,959 $ 595,386 Non-current assets................ 4,044,177 2,645,854 Current liabilities............... 3,535,352 786,713 Non-current liabilities. 2,608,827 1,303,003 Equity............................ 1,224,957 1,151,524
For the Year Ended December 31, ------------------------------- 2000 1999 ---------- ---------- (In Thousands) Income Statement: Revenues.......................... $6,642,858 $2,064,726 Gross profit...................... 797,132 632,350 Net income........................ 145,607 106,873
At December 31, 2000, the company's ownership interest in ONEOK is comprised of approximately 2.2 million common shares and approximately 19.9 million convertible preferred shares. If all the preferred shares were converted, the company would then own approximately 45% of ONEOK's common shares outstanding.
12. EMPLOYEE BENEFIT PLANS
Pension: The company maintains 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. The company's 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. The company also maintains a non-qualified Executive Salary Continuation Program for the benefit of certain management employees, including executive officers.
Postretirement Benefits: The company accrues the cost of postretirement benefits, primarily medical benefit costs, during the years an employee provides service.
The following tables summarize the status of the company's pension and other postretirement benefit plans:
For measurement purposes, an annual health care cost growth rate of 6.0% was assumed for 2000 decreasing to 5% in 2001 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 $2.5 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 $2.3 million and the aggregate of the service and interest cost components by $0.2 million.
Savings Plans: The company maintains savings plans in which substantially all employees participate, with the exception of Protection One and Protection One Europe employees. The company matches employees' contributions up to specified maximum limits. The company's contribution to the plans are deposited with a trustee and are invested in one or more funds, including the company stock fund. The company's contributions were $3.9 million for 2000, $3.7 million for 1999 and $3.8 million for 1998.
In 1999, the company established a qualified employee stock purchase plan, the terms of which allow for full-time non-union employees to participate in the purchase of designated shares of the company's common stock at no more than a 15% discounted price. Western Resources' employees purchased 249,050 shares in 2000, pursuant to this plan, at an average price per share of $13.9984. In 1999, employees purchased 72,698 shares at an average price per share of
$14.4234. 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, made at Protection One's election, 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 $0.7 million for 2000, $0.9 million for 1999 and $1.0 million for 1998.
Protection One maintains a qualified employee stock purchase plan that allows eligible employees to acquire shares of Protection One common stock at periodic intervals through their accumulated payroll deductions. A total of 2,650,000 shares of common stock have been reserved for issuance in this program and a total of 422,133 shares have been issued including the issuance of 145,523 shares in January 2001.
Stock Based Compensation Plans: The company, excluding Protection One and Protection One Europe, has a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan. The LTISA Plan was implemented as a means to attract, retain and motivate employees and board members (Plan Participants). Under the LTISA Plan, the company may grant awards in the form of stock options, dividend equivalents, share appreciation rights, restricted shares, restricted share units (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.
During 2000, 710,352 RSUs were granted to a broad-based group of over 900 non-union employees. Each RSU represents a right to receive one share of the company's common stock at the end of the restricted period. In addition, in 2000, current 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 restricted stock 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. The company granted a total of 152,000 restricted shares in 1999 and 136,500 in 1998.
Another component of the LTISA Plan is the Executive Stock for Compensation program where eligible employees are entitled to receive RSUs in lieu of cash compensation at the end of a deferral period. In 2000, 95,000 RSUs were deferred, representing $1.3 million in cash compensation. In 1999, 35,000 RSUs were deferred, representing $0.7 million of cash compensation. Dividend equivalents accrue on the deferred RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on the company's common stock.
Stock options and restricted shares under the LTISA plan are as follows:
Stock options and restricted shares issued and outstanding at December 31, 2000 are as follows:
An equal amount of dividend equivalents is issued to recipients of stock options and RSUs. The weighted-average grant-date fair value of the dividend equivalent was $4.62 in 2000 and $3.28 in 1999. The value of each dividend equivalent 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 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 1999 ----- ----- Dividend yield..................... 6.32% 6.25% Expected stock price volatility.... 16.42% 16.56% Risk-free interest rate............ 5.79% 6.05%
Protection One Stock Warrants and Options: Protection One has outstanding stock warrants and options which were considered reissued and exercisable upon the company's 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 employees. Under the LTIP, 4.2 million shares are reserved for issuance. 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.
A summary of warrant and option activity for Protection One from December 31, 1998, through December 31, 2000, is as follows:
(1) There were no outstanding stock or options prior to November 24, 1997.
Stock options and warrants of Protection One issued and outstanding at December 31, 2000, are as follows:
The weighted average fair value of options granted by Protection One during 2000, 1999 and 1998 estimated on the date of grant were $1.13, $5.41 and $6.87. The fair value was calculated using the following assumptions:
Year Ended December 31, ------------------------- 2000 1999 1998 ----- ----- ----- Dividend yield................... - % - % - % Expected stock price volatility.. 92.97% 64.06% 61.72% Risk free interest rate.......... 4.87% 6.76% 5.50% Expected option life............ 6 years 6 years 6 years
Effect of Stock-Based Compensation on Earnings Per Share: The company accounts for both the company's and Protection One's plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and the related interpretations. Had compensation expense been determined pursuant to Statement of Financial Accounting Standards No. 123, "Accounting for Stock- Based Compensation," the company would have recognized additional compensation costs during 2000, 1999 and 1998 as shown in the table below.
Split Dollar Life Insurance Program: The company has established a split dollar life insurance program for the benefit of the company and certain of its executives. Under the program, the company has purchased life insurance policies on which the executive's beneficiary is entitled to 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 the company. The company retains an equity interest in the death benefit and cash surrender value of the policy to secure this repayment obligation.
Subject to certain conditions, each executive may transfer to the company their interest in the death benefit based on a predetermined formula, beginning no earlier than the first day of the calendar year following retirement or three years from the date of the policy. The liability associated with this program was $19.1 million as of December 31, 2000, and $31.9 million as of December 31, 1999. The obligations under this program can increase and decrease based on the company's total return to shareholders and payments to plan participants. This liability decreased approximately $12.8 million in 2000 due primarily to payments to plan participants and $10.5 million in 1999 based on the company's total return to shareholders. There was no change in the liability in 1998. Under current tax rules, payments to active employees in exchange for their interest in the death benefits may not be fully deductible by the company for income tax purposes.
13. COMMON STOCK, PREFERRED STOCK AND OTHER MANDATORILY REDEEMABLE SECURITIES
The company's Restated Articles of Incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2000, 70,082,314 shares were issued and outstanding.
The company has a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP may be either original issue shares or shares purchased on the open market. During 2000, a total of 3,220,657 shares were purchased from the company made up of 1,440,000 treasury and 1,780,657 original issue shares. These shares were for DSPP, ESPP, 401K match and other stock based plans operated under the 1996 Long-term Incentive and Share Award Plan. Of the total shares purchased from the company in 2000, 2,750,457 were for the DSPP made up of 1,021,443 treasury and 1,729,014 original issue shares. During 2000 an additional 6,000,000 shares were registered to the DSPP. At December 31, 2000, 6,020,734 shares were available under the DSPP registration statement.
In 1999, the company purchased 900,000 shares of common stock at an average price of $17.55 per share. The purchased shares were purchased with short-term debt and available funds. These purchased shares are shown as $15.8 million in treasury stock on the accompanying Consolidated Balance Sheet. In 2000, the company purchased 540,000 shares of common stock at an average price of $17.01. All of these shares were reissued during the year.
Preferred Stock Not Subject to Mandatory Redemption: The cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at the option of the company.
Total Principal Call Amount Rate Outstanding Price Premium to Redeem ---- ----------- -------- ----------- -----------
4.500% $13,857,600 108.00% $1,108,608 $14,966,208 4.250% 6,000,000 101.50% 90,000 6,090,000 5.000% 5,000,000 102.00% 100,000 5,100,000 ----------- ---------- ----------- $24,857,600 $1,298,608 $26,156,208
The provisions in the company's Articles of Incorporation contain restrictions on the payment of dividends or the making of other distributions on the company's common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met.
Other Mandatorily Redeemable Securities: On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued 4.0 million preferred securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, for $100 million. The trust interests are redeemable at the option of Western Resources Capital I on or after December 11, 2000, at $25 per preferred 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 preference value of $25. Distributions are payable quarterly and are tax deductible by the company. These distributions are recorded as interest expense. The sole asset of the trust is $103 million principal amount of 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, of which the sole asset is subordinated debentures of the company, sold in a public offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, for $120 million. The trust interests 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 preference value of $25. Distributions are payable quarterly and are tax deductible by the company. These distributions are recorded as interest expense. The sole asset of the trust is $124 million principal amount of 8-1/2% Deferrable Interest Subordinated Debentures, Series B due July 31, 2036.
In addition to the company's obligations under the Subordinated Debentures discussed above, the company has agreed to guarantee, on a subordinated basis, payment of distributions on the preferred securities. These undertakings constitute a full and unconditional guarantee by the company of the trust's obligations under the preferred securities.
14. COMMITMENTS AND CONTINGENCIES
Efforts by Wichita to Equalize Electric Rates: In September 1999, the City of Wichita filed a complaint with FERC against KGE, alleging improper affiliate transactions between KGE and Western Resources' KPL division. The City of Wichita asked that FERC equalize the generation costs between KGE and KPL, in addition to other matters. On November 9, 2000, a FERC administrative law judge ruled in the company's favor that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. The company anticipates a decision by FERC in the second quarter of 2001. A decision requiring equalization of rates could have a material adverse effect on the company's operations and financial position.
Municipalization Efforts by Wichita: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay KGE $145 million for its stranded costs if the City were to municipalize. However, the company estimates the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse the company. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing the company adequate compensation for its assets and lost revenues, the adverse effect on the operations and financial position of the company could be material.
KGE's franchise with the City of Wichita to provide retail electric service expires in March 2002. There can be no assurance that this franchise can be successfully renegotiated 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, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 25% of the company's total energy sales .
Purchase Orders and Contracts: As part of its ongoing operations and construction program, the company has commitments under purchase orders and contracts which have an unexpended balance of approximately $154.2 million at December 31, 2000.
Manufactured Gas Sites: The company has been associated with 15 former manufactured gas sites located in Kansas which may contain coal tar and other potentially harmful materials. The company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at the 15 sites. The terms of the consent agreement will allow the company to investigate these sites and set remediation priorities based on the results of the investigations and risk analysis. At December 31, 2000, 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 the company's future liability associated with these sites to an immaterial amount. The company's investment earnings from ONEOK could be impacted by these costs.
Superfund Sites: In December 1999, the company was identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). The company has previously been associated with other Superfund sites for which the company's liability has been classified as de minimis and any potential obligations have been settled at minimal cost. Since 1993, the company has settled Superfund obligations at three sites for a total of $141,300. No Superfund obligations have been settled since 1994. The company's obligation, if any, at the Kansas City site is expected to be limited based upon previous experience and the limited nature of the company's business transactions with the previous owners of the site. In the opinion of the company's management, the resolution of this matter is not expected to have a material impact on the company's financial position or results of operations.
Clean Air Act: The company must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. The company has 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.
Decommissioning: The company accrues 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.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, the company's share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment. On May 26, 2000, the company filed an application with the KCC requesting approval of the funding of the company's decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000.
Decommissioning costs are currently being charged to operating expense in accordance with the prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2000 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%.
The company's investment in the decommissioning fund, including reinvested earnings approximated $64.2 million at December 31, 2000 and $58.3 million at December 31, 1999. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.
The FASB is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. The FASB has issued an Exposure Draft "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." The FASB expects to issue a final statement of financial accounting standard in the second quarter of 2001. The proposed Exposure Draft contains an effective date of fiscal years beginning after June 15, 2001. However, the ultimate effective date has not been finalized. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur:
- The company's annual decommissioning expense could be higher than in - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant
The company does not believe that such changes, if required, would adversely affect its operating results due to its current ability to recover decommissioning costs through rates.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the Nuclear Regulatory Commission (NRC). Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $88.1 million in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million in retrospective assessments per incident, per year.
The Owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, company's share). This insurance is provided by Nuclear Electric Insurance Limited (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. The company's 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.
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 losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, the company may be subject to retrospective assessments under the current policies of approximately $5.3 million per year.
Although the company maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, the company's 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 the company's financial condition and results of operations.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the company has 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, 2000, WCNOC's nuclear fuel commitments (company's share) were approximately $7.3 million for uranium concentrates expiring in 2003, $1.1 million for conversion expiring in 2003, $16.1 million for enrichment expiring at various times through 2003 and $61.3 million for fabrication through 2025.
At December 31, 2000, the company's coal and transportation contract commitments in 2000 dollars under the remaining terms of the contracts were approximately $1.52 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013.
At December 31, 2000, the company's natural gas transportation commitments in 2000 dollars under the remaining terms of the contracts were approximately $61.5 million. The natural gas transportation contracts provide firm service to several of the company's gas burning facilities and expire at various times through 2010, except for one contract which expires in 2016.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for an uranium enrichment decontamination and decommissioning fund. The company's portion of the assessment for Wolf Creek is approximately $9.6 million, payable over 15 years. Such costs are recovered through the ratemaking process.
15. LEGAL PROCEEDINGS
The SEC commenced a private investigation in 1997 relating to, among other things, the timeliness and adequacy of disclosure filings with the SEC by the company with respect to securities of ADT Ltd. The company is cooperating with the SEC staff in this investigation.
The company, its subsidiary Westar Industries, Protection One, its subsidiary
Protection One Alarm Monitoring, Inc. (Monitoring), and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Alec Garbini, et al v. Protection One, Inc., et al," No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint ("Amended Complaint"). Plaintiffs purport to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and notes, during the period of February 10, 1998 through February 2, 2001. The Amended Complaint asserts claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs allege, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Amended Complaint further asserts claims against the company and Westar Industries as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim is also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Amended Complaint seeks an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. Defendants have until April 9, 2001 to respond to the Amended Complaint. The company and Protection One intend to vigorously defend against all the claims asserted in the Amended Complaint. The company and Protection One cannot predict the impact of this litigation which could be material.
The company and its subsidiaries are involved in various other legal, environmental and regulatory proceedings. Management believes that adequate provision has been made and accordingly believes that the ultimate disposition of such matters will not have a material adverse effect upon the company's overall financial position or results of operations. See also Note 3 for discussion of regulatory proceedings and FERC proceedings including the City of Wichita and Note 14 for discussion of the City of Wichita municipalization efforts.
16. LEASES
At December 31, 2000, the company had leases covering various property and equipment.
Rental payments for operating leases and estimated rental commitments are as follows:
Year Ended December 31, Leases ------------------------------------------- (In Thousands) Rental payments: 1998......................... $70,796 1999......................... 71,771 2000......................... 71,232
Future commitments: 2001......................... $71,280 2002......................... 67,033 2003......................... 62,270 2004......................... 54,647 2005......................... 55,931 Thereafter................... 558,754 -------- Total future commitments... $869,915 ========
In 1987, KGE sold and leased back its 50% undivided interest in the La Cygne 2 generating unit. The La Cygne 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 La Cygne 2. The lease is an operating lease for financial reporting purposes. The company recognized a gain on the sale which was deferred and is being amortized over the initial lease term.
In 1992, the company deferred costs associated with the refinancing of the secured facility bonds of the Trustee and owner of La Cygne 2. These costs are being amortized over the life of the lease and are included in operating expense.
Future minimum annual lease payments, included in the table above, required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 2002, $39.4 million in 2003, $34.6 million in 2004, $38.0 million in 2005, and $464.6 million over the remainder of the lease. KGE's lease expense, net of amortization of the deferred gain and refinancing costs, was approximately $28.9 million annually for 2000, 1999 and 1998.
17. INTERNATIONAL POWER DEVELOPMENT COSTS
During the fourth quarter of 1998, management decided to exit the international power development business. This business had been conducted by the company's wholly owned subsidiary, The Wing Group. The company recorded a $98.9 million charge to income in the fourth quarter of 1998 as a result of exiting this business.
During 1999, the company terminated the employment of all employees, closed offices, discontinued all development activities, and terminated all other matters related to the activity of The Wing Group in accordance with the terms of the exit plan. These activities were substantially completed by December 31, 1999. The actual costs incurred during 1999 to complete the exit plan approximated $16.9 million, which was $5.6 million less than the amount estimated at December 31, 1998. This was accounted for as a change in estimate in 1999.
18. INCOME TAXES
Income tax expense (benefit) is composed of the following components at December 31:
2000 1999 1998 ------- -------- -------- (In Thousands) Currently payable: Federal................... $18,600 $ 13,907 $ 52,993 State..................... 10,131 9,622 10,881 Deferred: Federal................... 13,790 (43,090) (46,869) State..................... 9,585 (6,582) (4,185) Amortization of investment tax credits................ (6,045) (6,054) (6,065) ------- -------- -------- Total income tax expense (benefit).................. $46,061 $(32,197) $ 6,755 ====== ======== ========
Under SFAS No. 109, "Accounting for Income Taxes," temporary differences gave rise to deferred tax assets and deferred tax liabilities as follows at December 31:
2000 1999 ---------- ---------- (In Thousands) Deferred tax assets: Deferred gain on sale-leaseback....... $ 82,013 $ 87,220 Monitored services deferred tax assets 101,101 59,171 Other................................. 119,344 131,976 ---------- ---------- Total deferred tax assets............ $ 302,458 $ 278,367 ========== ==========
Deferred tax liabilities: Accelerated depreciation and other.... $ 609,396 $ 614,309 Acquisition premium................... 275,159 283,157 Deferred future income taxes.......... 188,006 218,937 Other................................. 58,158 40,508 ---------- ---------- Total deferred tax liabilities....... $1,130,719 $1,156,911 ========== ==========
Investment tax credits................. $ 91,546 $ 97,591 ========== ========== Accumulated deferred income taxes, net. $ 919,807 $ 976,135 ========== ==========
In accordance with various rate orders, the company has not yet collected through rates certain accelerated tax deductions which have been passed on to customers. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a regulatory asset for these amounts. These assets also are 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:
For the Year Ended December 31, ------------------------------- 2000 1999 1998 ------ ------ ------
Effective income tax rate................... 33.6% (108.6%) 16.6% Effect of: State income taxes......................... (9.4) (7.1) (7.3) Amortization of investment tax credits..... 4.4 20.4 14.9 Corporate-owned life insurance policies.... 8.4 28.0 22.4 Affordable housing tax credits............. 7.8 31.3 3.1 Accelerated depreciation flow through and amortization, net..................... (4.9) (12.2) (4.4) Adjustment to tax provision................ - 4.3 (16.9) Dividends received deduction............... 7.1 34.3 23.9 Amortization of goodwill................... (13.0) (19.3) (17.0) Other...................................... 1.0 (6.1) (0.3) ----- ------ ----- Statutory federal income tax rate........... 35.0% (35.0%) 35.0% ===== ====== =====
19. RELATED PARTY TRANSACTIONS
The company and ONEOK have shared services agreements in which facilities, utility field work, information technology, customer support, bill processing, and human resources services are provided to and billed to one another. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses. ONEOK paid the company $5.0 million in 2000 and $5.6 million in 1999, net of what the company owed ONEOK, for services.
In 1999, the company sold 984,000 shares of ONEOK stock to ONEOK as a result of ONEOK's repurchase program. The company reduced its investment in ONEOK for proceeds received from this sale. All such shares were required to be sold to ONEOK in accordance with a shareholder agreement between the company and ONEOK. The company's ownership interest remains at approximately 45% as of December 31, 2000.
2O. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
2000 1999 ---------- ---------- (In Thousands)
Electric plant in service........... $5,987,920 $5,769,401 Less - accumulated depreciation..... 2,274,940 2,141,037 ---------- ---------- 3,712,980 3,628,364 Construction work in progress....... 189,853 170,061 Nuclear fuel (net).................. 30,791 28,013 ---------- ---------- Net utility plant.................. 3,933,624 3,826,438 Non-utility plant in service........ 113,040 92,872 Less - accumulated depreciation..... 53,226 29,866 ---------- ---------- Net property, plant and equipment.. $3,993,438 $3,889,444 ========== ==========
The company's depreciation expense on property, plant and equipment was $201.7 million in 2000, $186.1 million in 1999 and $168.9 million in 1998.
21. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 2000 --------------------------------------------------- In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent ---------- ---------- ------------ ----- ---- (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 182,794 $ 115,903 344.0 50 Jeffrey 1 (b) Jul 1978 305,838 144,009 625.0 84 Jeffrey 2 (b) May 1980 297,979 133,701 622.0 84 Jeffrey 3 (b) May 1983 410,926 175,482 623.0 84 Jeffrey wind 1 (b) May 1999 828 58 0.6 84 Jeffrey wind 2 (b) May 1999 828 57 0.6 84 Wolf Creek (c) Sep 1985 1,381,656 491,978 550.0 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with UtiliCorp United Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity presented above represent the company's share. The company's share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in La Cygne 2 (representing 337 MW capacity) sold and leased back to KGE in 1987, are included in operating expenses on the Consolidated Statements of Income. The company's share of other transactions associated with the plants is included in the appropriate classification in the company's Consolidated Financial Statements.
22. SEGMENTS OF BUSINESS
In 1998, the company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires the company to define and report the company's business segments based on how management currently evaluates its business.
Management has segmented its business based on differences in products and services, production processes, and management responsibility. Based on this approach, the company has identified four reportable segments: Fossil Generation, Nuclear Generation, Power Delivery and Monitored Services.
The first three segments comprise the company's electric utility business. Fossil Generation produces power for sale internally to the Power Delivery segment and externally to wholesale customers. A component of the company's Fossil Generation segment is power marketing which attempts to minimize market fluctuation risk associated with fuel and purchased power requirements and enhance system reliability. Nuclear Generation represents the company's 47% ownership in the Wolf Creek nuclear generating facility. This segment has only internal sales because it provides all of its power to its co-owners. The Power Delivery segment consists of the transmission and distribution of power to the company's retail customers in Kansas and the customer service provided to these customers and the transportation of wholesale energy. Monitored Services represents the company's security alarm monitoring business in North America, the United Kingdom and continental Europe. Other represents the company's non- utility operations and natural gas investment.
The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. The company evaluates segment performance based on earnings before interest and taxes (EBIT). Unusual items, such as charges to income, may be excluded from segment performance depending on the nature of the charge or income. The company's ONEOK investment, marketable securities investments and other equity method investments do not represent operating segments of the company. The company has no single external customer from which it receives ten percent or more of its revenues.
(a) EBIT includes the gain on the sale of the company's investment in a gas compression company of $91.1 million and the gain on the sale of other marketable securities of $24.9 million. (b) Identifiable assets includes eliminating and reclassing balances to consolidate the monitored services business. (c) EBIT includes investment earnings of $36.0 million, an impairment of marketable securities of $76.2 million and the write-off of deferred costs of $17.6 million. (d) EBIT includes investment earnings of $21.7 million and the write-off of international power development costs of $98.9 million.
Geographic Information: Prior to 1998, the company did not have international sales or international property, plant and equipment. The company's sales and property, plant and equipment are as follows:
For the Year Ended December 31, -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (In Thousands) External sales: North America operations........... $2,262,381 $1,867,081 $1,990,329 International operations........... 106,095 163,006 43,725 ---------- ---------- ---------- Total............................ $2,368,476 $2,030,087 $2,034,054 ========== ========== ==========
As of December 31, -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (In Thousands)
Property, plant and equipment, net: North America operations........... $3,985,331 $3,881,294 $3,792,645 International operations........... 8,107 8,150 7,271 ---------- ---------- ---------- Total............................ $3,993,438 $3,889,444 $3,799,916 ========== ========== ==========
23. 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. The electric business of the company is seasonal in nature and, in the opinion of management, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND - ------------------------------------------------------------------------ FINANCIAL DISCLOSURE - --------------------
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - -----------------------------------------------------------
Director (age), year first became a director: Description
Directors (Class I) - Term Expiring in 2OO3
Charles Q. Chandler, IV (47), 1999: Mr. Chandler is Chairman of the Board, President, and Chief Executive Officer of INTRUST Bank, N.A. (since February 1996) and President of INTRUST Financial Corporation. Mr. Chandler was Executive Vice President and Vice Chairman of INTRUST Bank, N.A. until 1996. Both companies are located in Wichita, Kansas. Mr. Chandler is a director of INTRUST Financial Corporation, the First National Bank of Pratt, Kansas, the Will Rogers Bank in Oklahoma City, Oklahoma, and the Wesley Medical Center in Wichita, Kansas, and a trustee for the Kansas State University Endowment Foundation.
John C. Dicus (67), 199O: Mr. Dicus is Chairman of the Board and Chief Executive Officer of Capitol Federal Savings Bank. Mr. Dicus is also Chairman of the Board and Chief Executive Officer of Capitol Federal Financial and Capitol Federal Savings Bank MHC (since march 1999). These companies are located in Topeka, Kansas. Mr. Dicus is a director for Security Benefit Life Insurance Company and Columbian National Title Company, and a trustee of the Menniger Foundation, Stormont-Vail HealthCare, Inc. and the Kansas University Endowment Association.
Douglas T. Lake (5O), 2OOO: Mr. Lake is Executive Vice President and Chief Strategic Officer of the company (since September 1998). Prior to that Mr. Lake was Senior Managing Director at Bear, Stearns & Co. Inc., an investment banking firm. Mr. Lake is also Chairman of the Board of Protection One, Inc., and a director of ONEOK, Inc. and Guardian International, Inc.
Owen F. Leonard (6O), 2OOO: Mr. Leonard is President of KL Industries, Saddle Brook, New Jersey. KL Industries is privately held investment company which manufactures equipment for the electronics industry. Mr. Leonard is a director for QuVIS, Inc., Fox Run Holdings, Inc. and Waco Instruments, Inc.
Directors (Class II) - Term Expiring in 2OO1
Gene A. Budig (61), 1999: Dr. Budig is Senior Advisor to the Commissioner of Baseball in New York, New York (since March 2000). Prior to that time, Dr. Budig was President of the American League of Professional Baseball Clubs. Dr. Budig is a director of the Harry S. Truman Library Institute, the Ewing Marion Kaufman Foundation, the Major League Baseball Hall of Fame and the Media Studies Center-Freedom Forum.
John C. Nettels, Jr. (44), 2OOO: Mr. Nettels is a Partner with the law firm of Morrison & Hecker, L.L.P. in Wichita, Kansas.
David C. Wittig (45), 1996: Mr. Wittig is Chairman of the Board, President, and Chief Executive Officer of the Company (since January 1999, March 1996, and July 1998, respectively). Prior to that time, Mr. Wittig was Executive Vice President of Corporate Development. Mr. Wittig is a director of Waco Instruments, Inc. and Fox Run Holdings, Inc. Mr. Wittig is a trustee of the Kansas University Endowment Association and Boys Harbor, Inc.
Directors (Class III) - Term Expiring in 2OO2
Frank J. Becker (65), 1992: Mr. Becker is President of Becker Investments, Inc. in Lawrence, Kansas. Mr. Becker is a director of the Douglas County Bank, Martin K. Eby Construction Company, and IMA Insurance, Inc., and a trustee of the Kansas University Endowment Association.
Louis W. Smith (58), 1991: Mr. Smith is President and Chief Executive Officer (since July 1997) of the Ewing Marion Kauffman Foundation in Kansas City, Missouri. Mr. Smith is a director of the Ewing Marion Kauffman Foundation, Sprint Corporation, H & R Block, Inc., and Midwest Research Institute.
See "Executive Officers of the Company" in "Item 1. Business," for the information relating to the company's Executive Officers as required by Item 10 which is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION - --------------------------------
The information required by Item 11 will be included in an amendment to this Form 10-K 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 included in an amendment to this Form 10-K to be filed by us with the SEC.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - --------------------------------------------------------
None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - --------------------------------------------------------------------------
The following financial statements are included herein.
FINANCIAL STATEMENTS - --------------------
Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 2000 and 1999 Consolidated Statements of Income, for the years ended December 31, 2000, 1999 and 1998 Consolidated Statements of Comprehensive Income, for the years ended December 31, 2000, 1999 and 1998 Consolidated Statements of Cash Flows, for the years ended December 31, 2000, 1999 and 1998 Consolidated Statements of Shareholders' Equity, for the years ended December 31, 2000, 1999, and 1998 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 - -------------------
Form 8-K filed November 17, 2000 - Announcement of merger agreement between Public Service Company of New Mexico and Western Resources.
Form 8-K filed November 27, 2000 - Press release announcing that Western Resources. and KGE filed separate requests with the KCC seeking recovery of investments in new power plants and higher operating and maintenance costs.
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.
WESTERN RESOURCES, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands)
(a) Consists of costs to close duplicate facilities and severance and compensation benefits. (b) See Note 17 of Notes to the Consolidated Financial Statements for further information.
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.
WESTERN RESOURCES, INC.
Date April 2, 2001 By /s/ DAVID C. WITTIG - ------------------- --------------------------------------- David C. Wittig, Chairman of the Board, President and Chief Executive Officer
SIGNATURES ----------
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: