ITEM 2. PROPERTIES
Electric Facilities
At December 31, 2004, we owned generating facilities with an aggregate generating capacity of 1,102 megawatts.
Our principal electric baseload generating plant is the Asbury Plant with 210 megawatts of generating capacity. The plant, located near Asbury, Missouri, is a coal-fired generating station with two steam turbine generating units.
The plant presently accounts for approximately 19% of our owned generating capacity and in 2004 accounted for approximately 40% of the energy generated by us. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring. Every fifth year the maintenance outage is scheduled to be extended to a total of six weeks to permit inspection of the Unit No. 1 turbine. The last such outage took place from September 15, 2001 to December 17, 2001, a total of thirteen weeks. The 2001 five-year major generator turbine inspection was extended to allow for expanded boiler maintenance and the replacement of the control system. The next such outage is scheduled for the spring of 2007. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was also inspected during the 2001 outage. As of December 31, 2004, Unit No. 2 has operated approximately 2,500 hours since its last turbine inspection. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel costs associated with replacement energy.
Our generating plant located at Riverton, Kansas, has two steam-electric generating units with an aggregate generating capacity of 92 megawatts and three gas-fired combustion turbine units with an aggregate generating capacity of 44 megawatts. The steam-electric generating units burn coal as a primary fuel and have the capability of burning natural gas. Unit No. 8 was taken out of service from February 14, 2003 to May 14, 2003 for its scheduled five-year maintenance outage as well as to make necessary repairs to a high-pressure cylinder. The next five-year scheduled maintenance outage for the Riverton Plant’s other coal-fired unit, Unit No. 7, is scheduled for October 1 through November 13, 2005. We have purchased, and currently expect to install at our Riverton plant, a Siemens V84.3A2 combustion turbine with an expected capacity of 155 megawatts to be operational in 2007.
We own a 12% undivided interest in the 670 megawatt coal-fired Unit No. 1 at the Iatan Generating Station located 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of the unit’s available capacity and are obligated to pay for that percentage of the operating costs of the unit. Kansas City Power & Light and Aquila own 70% and 18%, respectively, of the Unit. Kansas City Power & Light operates the unit for the joint owners. See Note 10 of “Notes to Consolidated Financial Statements” under Item 8.
We have four combustion turbine peaking units, including two FT8 peaking units installed in 2003, at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 271 megawatts. These peaking units operate on natural gas as well as oil. On January 7, 2004, one of the original combustion turbine peaking units, Unit No. 2, experienced a rotating blade failure. Upon dismantling and inspecting the unit, we found damage to rotating and stationary components in the turbine as well as anomalies in the generator. We incurred $4.1 million of insurable costs to repair this facility, including a $1 million insurance deductible we expensed in the first quarter of 2004 related to this damage, and, as of December 31, 2004, had received $1.2 million in insurance reimbursement and recorded a $1.9 million receivable for the remaining insurance claims. We received an additional $0.6 million insurance reimbursement payment in January 2005 and expect to receive the remaining $1.3 million from our insurer.
Our State Line Power Plant, which is located west of Joplin, Missouri, presently consists of Unit No. 1, a combustion turbine unit with generating capacity of 89 megawatts and a Combined Cycle Unit with generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc. which owns the remaining 40% of the unit. We are the operator of the Combined Cycle Unit. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the capability of burning oil.
Our hydroelectric generating plant, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We replaced two of the four water wheels at our hydroelectric plant in 2003, finished
replacing the third wheel in early 2004 and began replacement of the fourth and final wheel in the fall of 2004 with completion in March 2005. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri.
On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed Elk River Windfarm which will be located in Butler County, Kansas. We anticipate purchasing approximately 550,000 megawatt-hours of energy annually from the project beginning in December 2005. We will not own any portion of the windfarm. On January 24, 2005, Flint Hills Tallgrass Prairie Heritage Foundation, Inc. filed a purported class action complaint in the United States District Court (the Court) seeking to halt the development or operation of industrial wind turbine electric power generation facilities within the Flint Hills Tallgrass Prairie Ecosystem. This complaint was dismissed by the Court with prejudice on February 11, 2005. A notice of appeal has been filed. See Item 3, “Legal Proceedings”.
At December 31, 2004, our transmission system consisted of approximately 22 miles of 345 kV lines, 430 miles of 161 kV lines, 747 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,566 miles of line.
Our electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common with Kansas City Power & Light and Aquila in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our property, plant and equipment are subject to the Mortgage.
Water Facilities
We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 84 miles of water mains in three communities in Missouri.
Other
We also have investments in non-regulated businesses which we commenced in 1996. These businesses are operated through our wholly-owned subsidiary EDE Holdings, Inc., which we created in 2001 to hold our non-regulated companies. As of December 31, 2004, we owned: a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business; a 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software, a 100% interest in Southwest Energy Training that offers technical training to the utility industry; a 100% interest in Utility Intelligence, Inc., a company that distributes automated meter reading equipment, a 100% interest in Fast Freedom, Inc., an Internet provider; and a controlling 50.01% interest in MAPP, a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, including components for specialized batteries for Eagle Picher Technologies. We sold E-Watch, our electronic monitored security company, to Federal Protection, Inc. of Springfield, Missouri in December 2002 after it did not meet our earnings expectations. In February 2003, we purchased Joplin.com, a leading Internet service provider in the Joplin, Missouri area. The purchase was made through our non-regulated subsidiary, Transaeris, and we merged Transaeris and Joplin.com into one company under the name Fast Freedom, Inc. On January, 31, 2005, we sold our interest in Southwest Energy Training. This divestiture will not have a material impact on our balance sheets or statements of income in future periods.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On December 10, 2004, Empire entered into a contract with PPM Energy to purchase the energy generated at the proposed Elk River Windfarm which will be located in Butler County, Kansas. The Elk River project has been developed by Greenlight Energy. On January 24, 2005, Flint Hills Tallgrass Prairie Heritage Foundation, Inc. filed a purported class action complaint in the United States District Court for the District of Kansas (the Court) styled Flint Hills Tallgrass Prairie Heritage Foundation, Inc. v. Scottish Power, PLC, et al., No. 05-1025JTM (D.
Kansas), against, among others, The Empire District Electric Company. Also named as defendants in the action are Scottish Power, PLC, PacificCorp, PPM Energy, Inc., Greenlight Energy, Inc. and Elk River Windfarm LLC. The plaintiffs seek various forms of declaratory and injunctive relief under the United States and Kansas Constitutions as well as various statutory and common law bases. Plaintiffs seek, among other things, to enjoin the defendants from any development or operation of industrial wind turbine electric power generation facilities within the Flint Hills Tallgrass Prairie Ecosystem and challenge the tax status of any such facility. Empire believes this case is without merit and will defend it vigorously. The complaint was dismissed with prejudice by the Court on February 11, 2005. A notice of appeal has been filed.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5.
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange. On March 1, 2005, there were 6,153 record holders and 27,485 individual participants in security position listings. The high and low sale prices for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter of 2004 and 2003 were as follows:
Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors. We pay dividends out of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2004, our retained earnings balance was $29.1 million after paying out $32.6 million in dividends during 2004.
The Mortgage and the Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined in the Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. As of December 31, 2004, our level of retained earnings did not prevent us from issuing dividends. In addition, under certain circumstances (including defaults thereunder), our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock.
During 2004, no purchases of our common stock were made by or on behalf of us.
Participants in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.
Our shareholders rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. See Note 5 of “Notes to Consolidated Financial Statements” under Item 8 for additional information. In addition, we have stock based compensation programs which are described in Note 4 of “Notes to Consolidated Financial Statements” under Item 8.
Our By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share acquisitions of our capital stock.
See Note 4 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding our common stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands, except per share amounts)
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
The Empire District Electric Company is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. We also provide water service to three towns in Missouri and have investments in some non-regulated businesses including fiber optics, Internet access, close-tolerance custom manufacturing and customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc. In 2004, 93.0% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.6% from our non-regulated businesses.
The primary drivers of our electric operating revenues in any period are: (1) weather, (2) rates we can charge our customers, (3) customer growth, (4) the ability (or inability due to the lack of a fuel adjustment provision in Missouri) to recover increases in fuel costs in rates and (5) general economic conditions. Weather affects the demand for electricity for our regulated business. Very hot summers and very cold winters increase demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and general economic conditions. The utility commissions in the states in which we operate, as well as the FERC, set the rates at which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely rate relief. We continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual customer growth to be approximately 1.6% over the next several years. We define sales growth to be growth in kWh sales excluding the impact of weather. The primary drivers of sales growth are customer growth and general economic conditions.
The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, (3) employee pension and health care costs, (4) taxes and (5) non-cash items such as depreciation and amortization expense. Fuel and purchased power costs are our largest expense items. Several factors affect these costs, including fuel and purchased power prices, plant outages and weather, which drives customer demand. In order to control the price we pay for fuel and purchased power, we have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and improve predictability. We have purchased, and will install at our Riverton facility, a Siemens V84.3A2 combustion turbine with a summer rated capacity of 155 megawatts to be operational in 2007 to meet additional capacity requirements due to anticipated customer growth.
On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed Elk River Windfarm which will be located in Butler County, Kansas. We expect that the amount and percentage of electricity we generate by natural gas will decrease in 2006 and in the immediate future thereafter due to this contract. We anticipate purchasing approximately 550,000 megawatt-hours of energy, or 10% of our annual needs, from the project beginning in December 2005. We anticipate the cost of this contract to also be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation. We believe this project is a significant step in assuring that our shareholders and customers benefit from a balanced mix of generation options. With the improvements made in wind generation technology and the extension of the production tax credits, wind energy provides price stability, is environmentally friendly and is economical for our customers.
For the twelve months ended December 31, 2004, basic and diluted earnings per weighted average share of common stock were $0.86 as compared to $1.29 for the twelve months ended December 31, 2003.
The following reconciliation of earnings per share between 2003 and 2004 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current year. The reconciliation presents the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the years ended December 31, 2003 and 2004 shown in the reconciliation are presented on a GAAP basis and are the same as
the amounts included in the statements of income. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.
Fourth Quarter Results
Revenues for the fourth quarter of 2004 were $74.3 million compared to $73.0 million in the fourth quarter of 2003. The increase in revenues was primarily driven by customer growth. Earnings for the fourth quarter of 2004 were $2.0 million, or $0.08 per share, compared to fourth quarter 2003 earnings of $4.8 million, or $0.21 per share. While an increase in revenues for the fourth quarter of 2004 contributed an estimated $0.04 per share in the fourth quarter of 2004 as compared to the fourth quarter of 2003, due to customer growth, increases in total fuel and purchased power costs reduced earnings per share by an estimated $0.08 per share. Also negatively impacting earnings were increases in health care expense, depreciation, property taxes and losses from our non-regulated business units.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the results of operations for 2004, compared to 2003, and for 2003, compared to 2002.
Electric Operating Revenues and Kilowatt-Hour Sales
Electric operating revenues comprised approximately 93% of our total operating revenues during 2004. Of these total electric operating revenues, approximately 41% were from residential customers, 31% from commercial customers, 17% from industrial customers, 4.5% from wholesale on-system customers, 2% from wholesale off-system transactions and 4.5% from miscellaneous sources, primarily transmission services. The breakdown of our customer classes has not significantly changed from 2003 or 2002.
The amounts and percentage changes from the prior periods in kilowatt-hour (“kWh”) sales and operating revenues by major customer class for on-system electric sales were as follows:
*
Percentage changes are based on actual kWhs and revenues and may not agree to the rounded amounts shown in this table.
***
Other kWh sales and Other Operating Revenues include street lighting, other public authorities and interdepartmental usage.
On-System Electric Transactions
KWh sales for our on-system customers increased slightly during 2004 primarily due to continued sales growth. Revenues for our on-system customers increased approximately $3.7 million, with an estimated $1.8 million of this increase attributed to the Oklahoma and FERC rate increases discussed below. Continued sales growth contributed an estimated $8.5 million to revenues during 2004, offset by an estimated $6.4 million negative effect from weather. Our customer growth was 1.7% in 2004 and 1.6% in both 2003 and 2002. We expect our annual customer growth to be approximately 1.6% over the next several years.
Residential kWh sales and revenues, which are more weather sensitive than the other sales classes, decreased in 2004 due primarily to milder temperatures, which had a negative effect on sales, during the first, third and fourth quarters of 2004 as compared to the same periods in 2003. Commercial sales and revenues and industrial sales and revenues, which are not particularly weather sensitive, increased during 2004 primarily due to the continued sales growth discussed above. Industrial sales also benefited from the addition of two new oil pipeline pumping stations on our system that became fully operational in June 2003. In addition, industrial revenues, as well as residential and commercial revenues, were favorably impacted by the August 2003 Oklahoma rate increase.
On-system wholesale kWh sales decreased slightly while revenues associated with these FERC-regulated sales increased as a result of the FERC rate increase that became effective May 1, 2003 and as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs. The decrease in kWh sales was mainly due to the change in customer status in June 2003 of an on-system wholesale customer/aggregator, comprising three of our on-system wholesale accounts, which elected to go off-system and purchase power from us at market-based rates. Revenues received from these accounts,
which comprised 5-6% of our on-system wholesale sales and revenues, but less than one-half percent of our total on-system sales and revenues in 2002, are now included in our off-system revenues.
KWh sales for our on-system customers increased slightly during 2003 as compared to 2002, primarily due to continued sales growth. Colder temperatures during the first quarter of 2003 as compared to milder temperatures during the same period in 2002 had a positive effect on sales with a new all-time winter peak of 987 megawatts being established on January 23, 2003, replacing the previous winter peak of 941 megawatts established in December 2000. However, the increase in first quarter sales was offset by unfavorable weather in the second, third and fourth quarters of 2003 notwithstanding setting a new summer peak demand of 1,041 megawatts on August 25, 2003. Despite only a slight increase in kWh sales, revenues from our on-system customers increased approximately $15.6 million, with an estimated $13 million of this increase attributed to the Missouri, Oklahoma and FERC rate increases discussed below with the remainder attributed to continued sales growth. This continued sales growth contributed an estimated $7 million to revenues during 2003 offset by an estimated $5 million negative effect from weather.
Notwithstanding the new summer peak demand, the slight increases in residential and commercial kWh sales in 2003 were due primarily to the continued sales growth discussed above. Industrial sales and revenues, which are not particularly weather sensitive, increased during 2003 mainly due to increased sales resulting from the addition of the two new oil pipeline pumping stations on our system in June 2003. Also contributing to the increase were increased sales during the first quarter of 2003 because of better economic conditions as compared to the first quarter of 2002 when our service territory experienced a general slowdown in economic activity. In addition, industrial revenues, as well as residential and commercial revenues, were favorably impacted by the December 2002 Missouri rate increase and, to a lesser extent, the August 2003 Oklahoma rate increase.
On-system wholesale kWh sales decreased due mainly to the change in customer status in June 2003 of the on-system wholesale customer/aggregator which elected to go off-system and purchase power from us at market-based rates. Overall revenues associated with these FERC-regulated sales increased as a result of the FERC rate increase that became effective May 1, 2003 and as a result of the fuel adjustment clause applicable to such sales.
Rate Matters
The following table sets forth information regarding electric and water rate increases granted during the four year period ended December 31, 2004 affecting the revenue comparisons discussed above:
The 2001 Missouri order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later which was collected subject to refund (with interest). The 2002 Missouri electric order called for us to refund all funds collected under the IEC, with interest, by March 15, 2003. The refunds were made in the first quarter of 2003 and did not have a material impact on our earnings in any of the years from 2001 through 2003.
On March 4, 2003, we filed a request with the Oklahoma Corporation Commission for an annual increase in base rates for our Oklahoma electric customers in the amount of $954,540, or 12.97%. On August 1, 2003 a Unanimous Stipulation and Agreement was approved by the Oklahoma Corporation Commission providing an annual increase in rates for our Oklahoma customers of approximately $766,500, or 10.99%, effective for bills rendered on or after August 1, 2003. This reflects a rate of return on equity (ROE) of 11.27%.
On March 17, 2003, we filed a request with the FERC for an annual increase in base rates for our on-system wholesale electric customers in the amount of $1,672,000, or 14.0%. This increase was approved by the FERC on April 25, 2003 with the new rates becoming effective May 1, 2003.
On April 30, 2004, we filed a request with the Missouri Public Service Commission (MPSC) for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. As part of the filing, we asked the Commission to consider, in addition to a traditional ratemaking approach, two options that would allow us to recover our actual fuel and purchased power expenses: an IEC, subject to refund, similar to the one approved in our 2001 case, or a fuel adjustment clause, that would reflect actual fuel prices. We subsequently abandoned our request for a fuel adjustment clause due to Missouri statutes not providing for such clauses but retained our request for the IEC, subject to refund. We also asked for a ROE of 11.65% and an annual increase in Missouri depreciation expense of approximately $10 million.
On May 20, 2004, we filed a request with the MPSC to implement the proposed IEC no later than June 15, 2004. However, the MPSC denied this request on August 12, 2004. On September 20, 2004, the Staff of the MPSC filed direct testimony in response to our initial April 2004 filing recommending an IEC be adopted for a period of 24 months, due to the extreme volatility currently exhibited by natural gas prices. We completed two weeks of evidentiary hearings during December 2004. Items that were covered during the hearings were: ROE, depreciation, base fuel and purchased power costs and the term and amount of an IEC. On February 22, 2005, we, the Office of Public Counsel (OPC) and two intervenors filed a Nonunanimous Stipulation and Agreement Regarding Fuel and Purchased Power Expense establishing a three-year refundable IEC which became unanimous by operation of Commission rule on March 1, 2005.
Prior to the hearings, we were able to settle several miscellaneous issues with other parties to the case. On December 22, 2004, we, the MPSC Staff, the OPC and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several of these issues. One of the issues we were able to agree on was a change in the recognition of pension costs. See Item 8 - “Financial Statements and Supplementary Data - Note 1 - Pensions” and “Note 8 - Retirement Benefits - Pensions.”
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25.7 million, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in depreciation rates and an increase in base rates for fuel and purchased power at $24.68/MWH. In addition, the order approved an annual Interim Energy Charge (IEC) of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.0021 per kilowatt hour of customer usage. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the MPSC to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, the excess money collected from customers, if any, above $10 million of the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time. At the end of the three year term of the IEC all excess money collected from customers, if any, of the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time.
On July 14, 2004, we filed a request with the Arkansas Public Service Commission for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. Any new rates approved as a result of this request are not expected to be effective until the second quarter of 2005.
On March 2, 2005, we notified the Kansas Corporation Commission of our intent to file an application requesting a change in base rates for our Kansas electric customers. We plan to file this application in the second quarter of 2005.
We will continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.
Off-System Electric Transactions
In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers. The following table sets forth information regarding these sales and related expenses for the applicable periods ended December 31,:
The decrease in revenues less expenses in 2004 as compared to 2003 and in 2003 as compared to 2002 resulted primarily from the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003. We sold this energy in the wholesale market when it was not required to meet our own customers’ needs during that period. See “- Competition” below. These expenses are included in our discussion of purchased power costs below.
Operating Revenue Deductions
During 2004, total operating expenses increased approximately $9.9 million (3.8%) compared to 2003. Total fuel costs increased approximately $12.1 million (23.1%) during 2004 offset by a decrease in purchased power costs of approximately $7.4 million (12.2%), resulting in a net increase of $4.7 million for fuel and purchased power. The increase in fuel costs was primarily due to increased generation by both our coal fired and gas fired units during 2004 (an estimated $7.9 million) and lower volumes of hedged natural gas in 2004 as compared to 2003 combined with higher prices for the unhedged portion of the natural gas that we burned in our gas-fired units (an estimated $5.1 million). The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power reflecting that it was more economical to run our own generating units during 2004 than to purchase power. The decrease in purchased power costs also reflects the non-renewal of the short-term contracts for firm energy that ran from January 2002 through June 2003. Despite the overall increase in fuel costs due to increased generation and higher costs, the positive effect of our gas hedging program reduced fuel cost by $11.5 million in 2004 and $9.4 million in 2003, in each case as compared to buying all natural gas requirements on the spot market. Given the current market conditions, we don’t expect the results of our gas hedging program to reduce our 2005 fuel costs by amounts comparable to the 2004 and 2003 reductions. See “Hedging Activities” under “Critical Accounting Policies” for information on future hedging activity. We also expect fuel costs to increase in 2005 due to changes in delivered prices resulting from the expiration of our long-term coal and freight contracts. A long-term contract with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal (Powder River Basin) at the Asbury and Riverton Plants expired in December 2004. We signed a new, three-year contract with Peabody on December 15, 2004 that covers approximately 100% of our anticipated 2005 Western coal requirements, approximately 67% of our anticipated 2006 Western coal requirements and approximately 33% of our anticipated Western coal requirements for 2007. We also currently have a contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which provides for transportation of the Powder River Basin coal which will expire at the end of June 2005. In 2004 we accepted a binding proposal and are in the process of finalizing contractual terms and conditions on a new transportation contract. We expect that, beginning in July 2005, this coal will be delivered under the new transportation contract. The delivered price of coal under the new contracts is expected to be higher than the 2004 price during the first and second quarters of 2005, but we expect the delivered price increase to be substantially mitigated beginning in the third quarter of 2005 due to a combination of our new coal supply and coal transportation contracts. We also expect changes in gas prices to contribute to variances in fuel costs, partially offset by the impact of our hedging program.
Regulated - other operating expenses increased approximately $3.2 million (6.5%) during 2004 as compared to 2003 primarily due to a $1.2 million increase in employee health care costs, an approximate $0.8 million increase in stock compensation costs, a $0.9 million increase in customer accounts expense, of which $0.4 million was a first quarter 2004 addition to bad debt expense, a $0.5 million increase in steam power operating expenses at the Asbury and Riverton plants and a $0.5 million increase in general administrative expense due primarily to $0.6 million associated with Sarbanes-Oxley compliance. These increases were partially offset by a $0.7 million decrease
in transmission and distribution expense, a $0.6 million decrease in professional service expenses and a $0.5 million decrease in employee pension expense. Based on the performance of our pension plan assets through January 1, 2003, we were required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund approximately $0.3 million in 2004 in order to maintain minimum funding levels and contributed this $0.3 million to our pension plan in the first quarter of 2004. Based on the performance of our pension plan assets through December 31, 2004, we expect there will be no contribution required under ERISA in order to maintain minimum funding levels in 2005. This could change, however, based on actual investment performance, any future pension plan funding and finalization of actuarial assumptions. No minimum pension liability was required to be recorded as of December 31, 2003 or 2004. No significant changes are expected for our post-retirement benefits in 2005 as compared to 2004. See Note 8 of “Notes to Consolidated Financial Statements” under Item 8 for further discussion regarding our pension and post-retirement benefit plans.
Non-regulated operating expense for all periods presented is discussed below under “-Non-regulated Items”.
Maintenance and repairs expense increased approximately $0.9 million (4.4%) during 2004 as compared to 2003 primarily due to the $1.0 million insurance deductible recorded to expense in the first quarter of 2004 related to the maintenance on the Energy Center’s Unit No. 2 which experienced a rotating blade failure on January 7, 2004 (which caused damage throughout the machine) and to the second and third quarter maintenance costs related to repairs at the Energy Center not subject to insurance recovery. Also contributing to this increase was a $0.8 million increase in transmission and distribution maintenance and a $0.7 million increase in maintenance costs for the SLCC as compared to the prior year due mainly to a $1.8 million true-up credit (our share of the credit as 60% owners of the SLCC) received from Siemens Westinghouse in June 2003 related to our maintenance contract for the period July 2002 through June 2003 for the SLCC. These increases were partially offset by a $1.4 million decrease in maintenance costs for our coal-fired units during 2004 as compared to the prior year, reflecting the maintenance outages during the second quarter of 2003 when the Iatan Plant underwent a planned boiler outage, the Riverton Plant’s Unit No. 7 had a 12-day scheduled spring maintenance outage and Unit No. 8 had an extended maintenance outage that ran from February 14, 2003 until May 14, 2003.
Depreciation and amortization expense increased approximately $2.1 million (7.4%) during 2004 due to increased plant in service. Total provision for income taxes decreased approximately $4.7 million (29.8%) during 2004 due primarily to lower taxable income. Our effective federal and state income tax rate for 2004 was 34.1% as compared to 34.5% for 2003. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding income taxes. Other taxes increased $1.9 million (11.6%) during 2004 due mainly to increased property taxes reflecting our additions to plant in service and increased city taxes in the first quarter of 2004 as compared to the first quarter of 2003 when we had a decrease in city taxes resulting from the refund of the IEC in the first quarter of 2003.
During 2003, total operating expenses increased approximately $15.0 million (6.0%) compared to 2002. Total fuel costs increased approximately $2.6 million (5.2%) during 2003 offset by a decrease in purchased power costs of approximately $2.6 million (4.1%) making total combined fuel and purchased power costs in 2003 virtually the same as in 2002. The increase in total fuel costs reflects a $1 million payment in the fourth quarter of 2003, expensed as additional fuel costs in the third quarter of 2003, pursuant to a settlement with Enron of a fuel contract dispute, a $0.7 million unfavorable coal inventory adjustment in August 2003 and increased generation by our coal-fired units, reflecting the non-renewal of short-term contracts for firm energy discussed above. Despite the effectiveness of our natural gas procurement program, increased natural gas prices during 2003 led to a 16.6 % increase in our average cost of gas as compared to 2002. See Note 14 - “Risk Management and Derivative Financial Instruments” under Item 8, “Financial Statements and Supplementary Data” for information on the over hedged and qualified portions of our hedging activities. The decrease in purchased power costs primarily reflects a shift from serving our energy needs with purchased power to generating our own power, reflecting that it was more economical to run our own generating units during the third and fourth quarters of 2003 than to purchase power. This decrease in purchased power costs also reflects the decrease in off-system sales due to the non-renewal of the short-term contracts for firm energy discussed above.
Regulated - other operating expenses increased approximately $6.7 million (15.5%) during 2003 as compared to 2002. This increase was primarily due to an increase of $5.6 million in employee pension expense due primarily to a decline in the value of invested funds. Expenses relating to our employee health care plan contributed $0.6
million to the increase in regulated - other operating expenses while increases in insurance premiums added $0.4 million.
There were no expenses during 2003 relating to the terminated merger with Aquila, Inc. as compared with $1.5 million during 2002. Expenses related to the terminated merger in 2002 were primarily the result of expenses related to severance benefits incurred under our Change in Control Severance Pay Plan in the first quarter of 2002. These expenses are shown on the Other line in our Consolidated Statement of Income under the heading “Operating revenue deductions”.
Maintenance and repairs expense decreased approximately $4.5 million (18.3%) during 2003 as compared to 2002. Maintenance and repairs expense for the State Line and Energy Center units decreased approximately $6.1 million partially offset by an approximate $1.3 million increase in maintenance and repairs at our Riverton Plant reflecting a scheduled five-year maintenance outage for Unit No. 8 in the first and second quarters of 2003 as well as to make necessary repairs to a high-pressure cylinder. The decrease in maintenance and repairs expense for the State Line Combined Cycle Unit reflects, in part, the $1.8 million true-up credit received from Siemens Westinghouse discussed above as well as estimated monthly credits we have been accruing since July 2003. Monthly payments on this contract had been based on an assumption of 250 equivalent starts per unit each year. Actual starts during the twelve month period ended June 30, 2003, however, were significantly less than originally estimated resulting in the June 2003 true-up credit. We expensed maintenance costs and accrued a credit based on a combination of starts and actual monthly usage hours for the contract year ended June 30, 2004. As of December 31, 2003, we had accrued $0.9 million in estimated credits. A $0.5 million payment during the third quarter of 2002, per contract terms, to Westar Generating, Inc. (WGI) for maintenance expense related to our usage of the existing Unit No. 2 turbine prior to WGI’s 40% joint ownership of the State Line Combined Cycle Unit also contributed to the decreased maintenance expense in 2003. Lower payments during the first half of 2003 on our long-term operating plant maintenance contracts for outage services on Units No. 1 and No. 2 at the Energy Center and State Line Unit No. 1 as compared to the first half of 2002 when we were making additional payments of approximately $1.1 million also contributed to the decrease. Lastly, renegotiated terms for the Energy Center units and State Line Unit No. 1 contract for outage services reduced maintenance costs during 2003 by $0.5 million.
Depreciation and amortization expense increased approximately $2.6 million (10.0%) during 2003 due to increased plant in service. Total provision for income taxes increased approximately $2.4 million (17.6%) during 2003 due primarily to higher taxable income. Our effective federal and state income tax rate for 2003 was 34.5% as compared to 34.3% for 2002. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding income taxes.
Non-regulated Items
We began investing in non-regulated businesses in 1996. Our non-regulated businesses, which we operate through our wholly-owned subsidiary EDE Holdings, Inc., include leasing of fiber optics cable and equipment (which we are also using in our own operations), Internet access, close-tolerance custom manufacturing and customer information system software services. On January, 31, 2005, we sold our 100% interest in Southwest Energy Training, a company that offers technical training to the utility industry. This divestiture will not have a material impact on our balance sheets or statements of income in future periods. We evaluated our non-regulated businesses for impairment at December 31, 2004, and determined that no impairment exists based on our forecast of future net cash flows. Failure to achieve forecasted cash flows could result in an impairment in the future.
During 2004, total non-regulated operating revenue increased approximately $0.7 million (3.5%) while total non-regulated operating expense increased approximately $1.8 million (8.6%) as compared with 2003. The increase in revenues was mainly due to the activities of our fiber optics business and Fast Freedom, an Internet provider we own a 100% interest in. The increase in expenses was due mainly to MAPP, which we own a 50.01% interest in, and Conversant, Inc., a software company that we own a 100% interest in which began business in early 2002. Conversant markets Customer Watch, an Internet-based customer information system software, and began contributing revenues in the fourth quarter of 2003.
During 2003, total non-regulated operating revenue increased approximately $10.6 million while total non-regulated operating expense increased approximately $9.2 million as compared with 2002. The significant increases
during 2003 were primarily due to the inclusion of a full year of MAPP operating revenues and expenses as compared to the prior year results which reflected the acquisition of our 50.01% interest in MAPP in July 2002. The increase in expenses was also due to the activities of Conversant, Inc.
Our non-regulated businesses generated a $1.8 million net loss in 2004 as compared to a $1.4 million net loss in 2003 and a $1.5 million net loss in 2002.
Nonoperating Items
Total allowance for funds used during construction (AFUDC) decreased $0.1 million in 2004 and $0.3 million in 2003 due to lower levels of construction. See Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
Total interest charges on long-term debt decreased $1.4 million (5.4%) in 2004 as compared to 2003 primarily reflecting the refinancing we accomplished in 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates. See “- Liquidity and Capital Resources” for further information. Total interest charges on long-term debt increased $1.1 million (4.4%) in 2003 as compared to 2002 primarily reflecting the effects of the sale of $50.0 million of 7.05% senior notes on December 23, 2002, the sale of the $98 million of 4.5% senior notes in June 2003 and the redemption of the $100 million of senior notes in November 2003. Commercial paper interest decreased $0.6 million during 2004 as compared to 2003, reflecting decreased usage of short-term debt.
Other Comprehensive Income
The change in the fair value of the effective portion of our open gas contracts and our interest rate derivative contracts and the gains and losses on contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income as the net change in unrealized gain or loss. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in comprehensive income are reclassified to fuel, or interest expense, in the periods in which they are actually realized or no longer qualify for hedge accounting.
The following table sets forth the net-of-tax increase/(decrease) and the change in the fair market value (FMV) of our open contracts in Other Comprehensive Income for the years presented (in millions).
(1)
Reflected in fuel expense
Our average cost for our open financial hedges increased from $3.695/Dth at December 31, 2003 to $4.795/Dth at December 31, 2004.
We had entered into an interest rate derivative contract in May 2003 to hedge against the risk of a rise in interest rates impacting our 4.5% Senior Notes due 2013 prior to their issuance on June 17, 2003. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $2.7 million and have been capitalized as a regulatory asset and are being amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the redemption of the $100 million aggregate principal amount of our 7.70% Senior Notes due 2004. The $60 million 30-year interest rate derivative contract that we had entered
into on May 16, 2003 to hedge against the risk of a rise in interest rates impacting our 6.7% Senior Notes due 2033 prior to their issuance on November 3, 2003, expired on October 29, 2003 with a gain of $5.1 million. This amount was recorded as a regulatory liability and is being amortized against interest expense over the 30 year life of the debt issue we had hedged. See Note 6 - Long Term Debt under “Notes to Consolidated Financial Statements” under Item 8. We had no interest rate derivative contracts in 2002 or 2004.
Competition
Federal regulation has promoted and is expected to continue to promote competition in the wholesale electric utility industry. However, none of the states in our service territory has legislation that could require competitive retail pricing to be put into effect. The Arkansas Legislature passed a bill in April 1999 that called for deregulation of the state’s electricity industry as early as January 2002. However, a law was passed in February 2003 repealing retail deregulation in the state of Arkansas.
We, and most other electric utilities with interstate transmission facilities, have placed our facilities under FERC regulated open access tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool (SPP), a regional reliability coordinator of the North American Electric Reliability Council and FERC approved Regional Transmission Organization (RTO). Effective September 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. This provides a cost-effective way for us to participate in a broader market of generation resources with the possibility of lower transmission costs. This tariff provides for a zonal rate structure, whereby transmission customers within the same zone pay a pro-rata share, in the form of a reservation charge, for the use of the facilities for each transmission owner that serves them. Currently, all revenues collected within a zone are allocated back to the transmission owner serving the zone. To the extent that we are allocated revenues and charges to serve our on-system wholesale and retail power customers, only the difference, if any, is recorded. Revenues received from off-system transmission customers are reflected in electric operating revenues and the related charges expensed.
Prior to the time we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff, we had an agreement with Kansas City Power & Light (KCP&L) for transmission service from the Iatan plant. We believed we had the right to terminate the service under the older Iatan transmission agreement, whereas KCP&L contended that we did not. While we were working to resolve this dispute, we ceased scheduling service from KCP&L but continued to accrue (but not pay) the monthly amount we had paid under the original contract terms. We reached a settlement with KCP&L to pay approximately $0.8 million which was the amount that had accrued since October 2002 and was paid in August 2003, and to continue the service agreement with KCP&L through March 2004, at which time we were released from the original agreement. The additional cost for continuing the service agreement through March 2004 was approximately $0.7 million, which was paid in monthly installments.
In December 1999, the FERC issued Order No. 2000 which encourages the development of RTOs. RTOs are designed to independently control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive bulk power markets. On October 15, 2003, the SPP announced it had filed with the FERC seeking formal recognition as an RTO in accordance with FERC Order 2000 and on February 10, 2004, the FERC approved the SPP RTO with conditions. Upon completion of the conditions, the SPP would gain status and FERC acceptance as an RTO. On October 4, 2004, the FERC granted RTO status to the SPP and ordered the SPP to resolve rate “pancaking” (accumulation of multiple access charges) concerns and assure the independence of its proposed market monitor as conditions of the decision. FERC also ordered SPP to finalize a joint operating agreement with Midwest Independent Transmission System Operator, Inc. (MISO). These conditions have been addressed and the SPP is now operating as an RTO.
In October 2003, we filed a notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2004 because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind such notice on or before October 31, 2004 and remain a member of the SPP, which we did on October 25, 2004. At the same time, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2005. We will be seeking authorization from Missouri, Kansas and Arkansas to participate in and
transfer functional control of our transmission facilities to the SPP RTO should we decide to remain a member. As part of the applications to the aforementioned states, a formal independent SPP RTO Cost Benefit Analysis (CBA) will be submitted. It is anticipated that the completion of the CBA will be finalized by or before April 2005. We are unable to quantify the potential impact of membership in the RTO on our future financial position, results of operation or cash flows at this time, but will continue to evaluate the situation and make a decision whether or not to discontinue membership with the SPP.
In November 2003, FERC issued its Final Rule, Order 2004, with subsequent follow-up Orders regarding electric and natural gas industry Code of Conduct requirements for natural gas and electric transmission service providers and their affiliates. Such Orders are closely related to Order 889 standards of conduct for electric transmission providers and management of Open Access Same Time Information Systems (OASIS) for the power industry. In February 2004, we made an Informational Filing to FERC in response to Order 2004 describing our existing waiver, issued in May 1997, of Order 889 requirements and requesting the continuation of such waiver for Order 2004 requirements. In its April 2004 Order, FERC addressed existing 889 waivers/exemptions and affirmed that such existing waivers/exemptions would continue. If in the future, FERC determines that a waiver of Orders 889 or 2004 is not appropriate for us, then we will be required to separate our bulk power retail sales and purchase functions from our transmission operations functions as well as implement formal code of conduct training and OASIS practices.
In July 2004, FERC issued an order regarding new testing standards for assessing market power by entities that have wholesale market-based rates tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. Failure to show a lack of market power would result in the inability for a utility to continue to charge such market-based rates. Our filing has been submitted and followed by subsequent informational data filings to the FERC. On March 3, 2005, the FERC issued an order commencing an investigation to determine if we have market power within our control area based on our failure to meet one of FERC’s wholesale market share screens. We are required to file a response within 60 days. Even if the FERC does find we have market power within our control area, it will not have a material impact on our financial position because we currently have no market-price based wholesale customers within our control area. The outcome of FERC rulings for all utilities is pending.
Approximately 4.5% of our electric operating revenues are derived from sales to on-system wholesale customers, the type of customer for which the FERC is already requiring wheeling, or the use, for a fee, of transmission facilities owned by one company or system to move electrical power for another company or system. Our two largest on-system wholesale customers accounted for 92% of our wholesale business in 2004. We have contracts with these customers that run through the first quarter of 2008.
LIQUIDITY AND CAPITAL RESOURCES
Our net cash provided by operations was higher in 2004 as compared to 2003 due to the repayment in 2003 of a previously accumulated IEC. Investments were lower due to decreased construction. Our primary sources of cash flow during 2004 were $74.4 million in internally generated funds and $13.4 million in proceeds from the issuance of common stock, primarily related to our Dividend Reinvestment and Stock Purchase Plan. Our primary uses of cash during 2004 were $41.9 million in capital expenditures, $13.3 million in short-term debt repayments and $32.6 million in dividend payments.
Our capital expenditures are expected to increase during 2005-2007 due to the purchase and expected installation of a Siemens V84.3A2 combustion turbine with an expected capacity of 155 megawatts at our Riverton Plant to meet additional capacity requirements. This unit is expected to be operational in 2007. Our future construction expenditures include approximately $16.9 million in 2005, $13.5 million in 2006 and $14.1 million in 2007 for the purchase and installation of this turbine.
A detailed discussion on cash flow activity follows.
Cash Provided by Operating Activities
Our net cash flows provided by operating activities increased $4.6 million during 2004 as compared to 2003 primarily due to the refunding of $18.7 million to our Missouri electric customers in the first quarter of 2003 (the amount of the IEC, with interest, collected between October 2001 and December 2002). Other major factors positively impacting cash flows provided by operating activities during 2004 as compared to 2003 were a $2.4 million increase due to changes in accounts payable and accrued liabilities, a $2.7 million increase in depreciation and amortization due to increased plant in service and a $1.0 million increase due to changes in prepaid expenses and deferred charges. Negatively impacting cash provided by operating activities were a $7.6 million decrease in net income, a $6.0 million decrease due to higher accounts receivable and accrued unbilled revenues, a $4.0 million decrease in deferred income taxes associated with lower net income and a $3.8 million decrease due to changes in cash used for fuel, materials and supplies.
Our net cash flows provided by operating activities decreased $3.3 million during 2003 as compared to 2002 primarily due to the refunding of the $18.7 million to our Missouri electric customers in the first quarter of 2003. This outflow of cash in 2003 was partially offset by a $3.9 million increase in net income, a $6.9 million increase due to changes in accounts receivable and accrued unbilled revenues and a $3.3 million increase in depreciation and amortization due to increased plant in service during 2003. Also positively impacting cash flows provided by operating activities were (1) a deferred income tax increase of $3.2 million during 2003 as compared to 2002 primarily due to deferred taxes related to an additional first year depreciation tax allowance recorded for financial statement purposes primarily for our FT8 peaking units and the deduction for tax purposes of the loss on reacquired debt (unamortized issuance costs and discounts on the redeemed first mortgage bonds) and (2) a change from pension income of $3.6 million in 2002 to pension expense of $3.9 million in 2003 primarily due to a decline in the value of invested funds.
We do not expect a significant change in our cash flows from operating activities as a result of our 20-year contract with PPM Energy for the purchase of approximately 550,000 megawatt-hours of energy annually from the proposed Elk River Windfarm beginning in December 2005. We expect that the amount and percentage of electricity we generate by natural gas will decrease in 2006 and in the immediate future thereafter due to this contract. We anticipate the cost of this contract to also be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation.
Capital Requirements and Investing Activities
Our net cash flows used in investing activities decreased $24.0 million during 2004 as compared to 2003, primarily reflecting the completion of the two FT8 peaking units at the Empire Energy Center in April 2003.
Our net cash flows used in investing activities decreased $11.0 million during 2003 as compared to 2002, primarily reflecting completion of the two FT8 peaking units at the Empire Energy Center.
Our capital expenditures totaled approximately $41.9 million, $65.9 million, and $76.9 million in 2004, 2003 and 2002, respectively. These capital expenditures include AFUDC, increases in capitalized software costs, capital expenditures to retire assets and benefits from salvage.
A breakdown of these capital expenditures for 2004, 2003 and 2002 is as follows:
Approximately 99%, 58% and 63% of the cash requirements for capital expenditures for 2004, 2003 and 2002, respectively, were satisfied with internally generated funds (net cash provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and unsecured Senior Notes discussed below.
On July 17, 2002 our subsidiary, EDE Holdings, Inc., together with other investors, acquired the assets of the Precision Products Department of Eagle Picher Technologies, LLC. The acquisition was accomplished through the creation of a newly formed limited liability company, Mid-America Precision Products, LLC (MAPP). EDE Holdings, Inc. acquired a controlling 50.01% interest in MAPP through a cash investment of $0.65 million and, as of December 31, 2003, was the guarantor for 50.01% of a $2.4 million long-term note payable and a $0.75 million revolving short-term credit facility. Although our ownership interest in MAPP remained at 50.01%, as of January 1, 2004, our guaranty was lowered to 25%. However, as part of curing MAPP’s violation of certain financial covenants at December 31, 2004, MAPP’s loan covenants have been revised and, as of January 1, 2005, EDE Holdings, Inc, is again the guarantor of 50.01% of the remaining $2.7 million long-term note payable and the $0.85 million revolving short-term credit facility, of which $0.8 million was outstanding.
We estimate that our capital expenditures will total approximately $69.3 million in 2005, $86.0 million in 2006 and $88.4 million in 2007. Of these amounts, we anticipate that we will spend approximately $26.5 million, $26.9 million and $27.4 million in 2005, 2006 and 2007, respectively, for additions to our distribution system to meet projected increases in customer demand. These capital expenditure estimates also include approximately $16.9 million in 2005, $13.5 million in 2006 and $14.1 million in 2007 for the purchase and installation of a Siemens V84.3A2 combustion turbine at our Riverton Plant with an expected capacity of 155 megawatts which is scheduled to be operational in 2007 to meet additional capacity requirements.
We estimate that internally generated funds will provide 69% of the funds required in 2005 for capital expenditures. As in the past, we intend to utilize short-term debt or the proceeds of sales of long-term debt or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance any additional amounts needed for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. The estimates herein may be changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons.
Financing Activities
Our net cash flows used in financing activities increased $27.8 million to $33.0 million during 2004 as compared to 2003, primarily due to the borrowing and repayment of short-term debt (commercial paper), the payment of dividends on an increased number of shares of our common stock, partially offset by proceeds from stock issuances, and by the lack of issuances and redemptions of securities consummated in 2003 as described below.
Our net cash flows provided by financing activities decreased $12.0 million during 2003 as compared to 2002 resulting in a $5.3 million use of cash during 2003. Our net cash flows provided by financing activities in 2003 were primarily affected by issuances of common stock, senior notes and trust preferred securities and redemptions and repayments of senior notes and first mortgage bonds, each of which is described in detail below. Also increasing net cash flows provided by financing activities for 2003 was the receipt of $5.1 million from a realized gain resulting from an interest rate derivative, which was partially offset by a loss of $2.7 million on a similar interest rate derivative.
On May 22, 2002, we sold to the public in an underwritten offering 2,500,000 shares of newly issued common stock for $51.9 million. The net proceeds of approximately $49.4 million were used to repay $37.5 million of our First Mortgage Bonds, 7.50% Series due July 1, 2002 and to repay short-term debt.
On December 23, 2002, we sold to the public in an underwritten offering $50 million aggregate principal amount of our unsecured Senior Notes, 7.05% Series due 2022, which mature on December 15, 2022. The net proceeds of approximately $48.6 million were added to our general funds and used to repay short-term debt.
On June 17, 2003, we sold to the public in an underwritten offering, $98 million aggregate principal amount of our unsecured Senior Notes, 4.5% Series due 2013, for net proceeds of approximately $96.6 million. We used the net proceeds from this issuance, along with short-term debt, to redeem all $100 million aggregate principal amount of our Senior Notes, 7.70% Series due 2004 for approximately $109.8 million, including interest. We had entered into an interest rate derivative contract in May 2003 to hedge against the risk of a rise in interest rates impacting the 2013 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $2.7 million and were capitalized as a regulatory asset and are being amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the Senior Notes, 7.70% Series due 2004.
On November 3, 2003, we issued $62.0 million aggregate principal amount of Senior Notes, 6.70% Series due 2033 for net proceeds of approximately $61.0 million. We used the proceeds from this issuance, along with short-term debt, to redeem three separate series of our outstanding first mortgage bonds: (1) all $2.25 million aggregate principal amount of our First Mortgage Bonds, 9-3/4% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7-1/4% Series due 2028 for approximately $13.7 million, including interest; and (3) all $45.0 million aggregate principal amount of our First Mortgage Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against the risk of a rise in interest rates impacting the 2033 Notes prior to their issue. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and is being amortized over the life of the 2033 Notes as a reduction of interest expense.
We “marked-to-market” the fair market value of these contracts at the end of each accounting period and included the change in value in Other Comprehensive Income until they were reclassified as a regulatory asset upon issuance of the 2013 Notes in June 2003 and a regulatory liability upon issuance of the 2033 Notes in November 2003.
On December 17, 2003, we sold to the public in an underwritten offering, 2,000,000 newly issued shares of our common stock for $42.3 million. The net proceeds of approximately $40.3 million were used to repay short-term debt and for other general corporate purposes. On January 8, 2004, we sold an additional 300,000 shares to cover the underwriters’ over-allotments for approximately $6.1 million. The proceeds were added to our general funds.
During 2004 and 2003 we also issued $7.3 million and $6.9 million, respectively, in common stock pursuant to our stock plans, primarily through our employee stock purchase and dividend reinvestment plans.
We have an effective shelf registration statement with the SEC under which approximately $89 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance.
On October 22, 2004, we extended our $100 million unsecured revolving credit facility until May 31, 2006. Borrowings are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. The credit facility is used for working capital, general corporate purposes and to back up our use of commercial paper. This facility requires our total indebtedness (which does not include the Trust Preferred Securities or the related note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios would result in an event of default under the credit facility and would prohibit us from borrowing funds thereunder. We are in compliance with these ratios as of December 31, 2004. This credit facility is also subject to cross-default if we default on excess of $5,000,000 in the aggregate of our other indebtedness. There were no borrowings outstanding under this revolver as of December 31, 2004.
Short-term commercial paper outstanding and notes payable averaged $1.4 million and $42.8 million daily during 2004 and 2003, respectively, with the highest month-end balances in each year being $8.5 million and $74.4 million, respectively. Our commercial paper borrowings decreased to zero at December 31, 2004 compared to $13 million at December 31, 2003.
Restrictions in our mortgage bond indenture could affect our liquidity. The Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended December 31, 2004 would permit us to issue approximately $172.2 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2004, we had retired bonds and net property additions which would enable the issuance of at least $401.0 million principal amount of bonds if the annual interest requirements are met. We are in compliance with all restrictive covenants of the Mortgage.
The Mortgage and the Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined in the Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. As of December 31, 2004, our level of retained earnings did not prevent us from issuing dividends. In addition, under certain circumstances (including defaults thereunder), our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock.
As of December 31, 2004, the ratings for our securities were as follows:
On July 22, 2004, Standard & Poor’s notified us that they had upgraded their rating on our first mortgage bonds from BBB to A-. On September 28, 2004, Standard & Poor’s notified us that they had placed that rating on credit watch with negative implications reflecting, “prospects for erosion of Empire’s pressured financial condition if recent testimony by the MPSC staff in Empire’s pending general rate case is ultimately endorsed by the MPSC.” On March 14, 2005, Standard & Poor’s affirmed its ‘BBB/A-2’ corporate credit rating on us and removed the rating from credit watch with negative implications. The outlook is now stable reflecting the MPSC’s rate case decision on March 10, 2005 that exceeded expectation and supports our credit quality. Moody’s currently has a negative rating outlook on Empire. These ratings indicate the agencies’ assessment of our ability to pay interest, distributions, dividends and principal on these securities. The lower the rating the higher our financing costs will be when our securities are sold. Ratings below investment grade (Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt, commercial paper or other securities or make the marketing of such securities more difficult.
CONTRACTUAL OBLIGATIONS
Set forth below is information summarizing our contractual obligations as of December 31, 2004. Not included in these amounts are expected obligations associated with the installation of the new combustion turbine at Riverton, the wind energy agreement, postretirement benefit funding or any future pension funding commitments. These items are discussed in “Executive Summary”, “Liquidity and Capital Resources” and Item 8 - “Financial Statements and Supplementary Data - Note 8 - Retirement Benefits.”
*
includes fuel and purchased power contracts.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
CRITICAL ACCOUNTING POLICIES
Set forth below are certain accounting policies that are considered by management to be critical and to possibly involve significant risk, which means that they typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
Pensions. Our pension expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years. In compliance with FAS 87, additional gain or expense may be recognized when our unrecognized gain or loss exceeds 10% of our pension benefit obligation or fair value of plan assets. In addition, we record a liability when the accumulated benefit obligation of the plan exceeds the fair value of the plan assets. Our policy is consistent with the provisions of SFAS 87, “Employers’ Accounting for Pensions”.
In our most recently approved Missouri Rate Case (effective March 27, 2005), the MPSC ruled that we would be allowed to recover pension costs consistent with our GAAP policy noted above except that unrecognized actuarial gains or losses will now be amortized over a 10 year period. In accordance with the rate order, we will prospectively calculate the value of plan assets using the Market Related Value method 9 (as defined in SFAS 87). This is a change from the policy approved in the 2002 order, which allowed us to recover pension costs on an ERISA minimum funding (or cash) basis. Prior to the 2002 order, the MPSC allowed us to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA recovery allowed by the MPSC and our accounting for pension costs under GAAP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, we have continued to account for pension expense or benefits in accordance with SFAS 87, using the previously mentioned amortization formula for recognizing net gains or losses. We now expect future pension expense or benefits will be fully recovered or recognized in rates charged to customers.
Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Based on the performance of our pension plan assets through January 1, 2003, we were required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund approximately $0.3 million in 2004 in order to maintain minimum funding levels and contributed this $0.3 million to our pension plan in the first quarter of 2004. No minimum pension liability was required to be recorded as of December 31, 2003 or December 31, 2004. Factors that could result in additional pension expense include: a lower discount rate than estimated, higher compensation rate increases, lower return on plan assets, and longer retirement periods.
Postretirement Benefits. We recognize expense related to postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our postretirement expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years. Additional gain or expense may be recognized when our unrecognized gain or loss exceeds 10% of our postretirement benefit obligation or fair value of plan assets. Our policy is consistent with the provisions of SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. Factors that could result in additional postretirement expense include: a lower discount rate than estimated, higher compensation rate and medical cost rate increases, lower return on plan assets, and longer retirement periods.
Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates).
Hedging Activities. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized on the balance sheet with gains and losses from effective instruments deferred in other comprehensive income (in stockholders’ equity), while gains and losses from ineffective (overhedged) instruments are recognized as the fair value of the derivative instrument changes.
As of March 4, 2005, approximately 61% of our anticipated volume of natural gas usage for the remainder of the year 2005 is hedged at an average price of $4.795 per Dekatherm (Dth). In addition, approximately 40% of our anticipated volume of natural gas usage for the year 2006 is hedged at an average price of $4.760 per Dth,
approximately 37% of our anticipated volume of natural gas usage for the year 2007 is hedged at an average price of $4.526 per Dth, approximately 21% of our anticipated volume of natural gas usage for the year 2008 is hedged at an average price of $4.569 per Dth and approximately 40% of our anticipated volume of natural gas usage for the years 2009-2011 is hedged at an average price of $4.522 per Dth.
Risks and uncertainties affecting the application of this accounting policy include: market conditions in the energy industry, especially the effects of price volatility, regulatory and political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately in our Consolidated Statement of Income.
Regulatory Assets and Liabilities. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (FERC and four states).
Certain expenses and credits, normally recognized as incurred, are deferred as assets and liabilities on the balance sheet until the time they are recovered from or refunded to customers. This is consistent with the provisions of SFAS No. 71. We have recorded certain regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by our regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures, and we believe that the regulatory assets and liabilities we have recorded will be afforded similar treatment. If these items are not afforded similar treatment they will be required to be recognized in our statement of income.
As of December 31, 2004, we have recorded $52.1 million in regulatory assets and $30.2 million in income taxes, gain on interest rate derivatives and costs of removal as regulatory liabilities. See Note 3 of “Notes to Consolidated Financial Statements” under Item 8 for detailed information regarding our regulatory assets and liabilities.
We continually assess the recoverability of our regulatory assets. Under current accounting standards, regulatory assets and liabilities are eliminated through a charge or credit, respectively, to earnings if and when it is no longer probable that such amounts will be recovered through future revenues.
Risks and uncertainties affecting the application of this accounting policy include: regulatory environment, external regulatory decisions and requirements, anticipated future regulatory decisions and their impact and the impact of deregulation and competition on ratemaking process and the ability to recover costs.
Unbilled Revenue. At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy that has been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage and estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled period.
Contingent Liabilities. We are a party to various claims and legal proceedings arising in the ordinary course of our business. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2004, we believe that we have accrued liabilities in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5) sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2004 is $1.5 million.
Risks and uncertainties affecting these assumptions include: changes in estimates on potential outcomes of litigation and potential litigation yet unidentified in which we might be named as a defendant.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Item 8 - “Financial Statements and Supplementary Data - Note 1 - Recently Issued and Proposed Accounting Standards.”
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle our commodity market risk in accordance with our established Energy Risk Management Policy, which may include entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 14 of “Notes to Consolidated Financial Statements” for further information.
Interest Rate Risk. We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure (applicable only to commercial paper) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 6 and 7 of “Notes to Consolidated Financial Statements” under Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
of The Empire District Electric Company:
We have completed an integrated audit of The Empire District Electric Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 10, 2005
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS (continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Interest paid was $27,473,000, $30,935,000, and $30,943,000 for the years ended December 31, 2004, 2003, and 2002, respectively. Income taxes paid were $1,506,000, $0, and $1,767,000 for the years ended December 31, 2004, 2003, and 2002, respectively. Net income taxes paid in 2003 of $0 were due to payments offset by a refund of federal income tax of $750,000.
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
General
The Empire District Electric Company, headquartered in Joplin, Missouri, is primarily a regulated electric utility engaged in the generation, purchase, transmission, distribution and sale of electricity. Empire also provides regulated water utility service to three towns in Missouri. Currently, the regulated utility accounts for about 98% of consolidated assets and 93% of consolidated revenues. The utility portions of the business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Empire also has a wholly-owned non-regulated subsidiary, EDE Holdings, Inc. Through the non-regulated subsidiary, as of December 31, 2004, we leased capacity on our fiber optics network, provided Internet access, performed close-tolerance custom manufacturing (Mid America Precision Products, LLC (MAPP)) and licensed customer information system software services. For discussion of the activities of our non-regulated operations and non-regulated results of operations, see Note 12. Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities. Our electric revenues in 2004 were derived as follows: residential 41%, commercial 31%, industrial 17%, wholesale on-system 4.5%, wholesale off-system 2% and other 4.5%. Our electric revenues for 2004 by jurisdiction were as follows: Missouri 88.7%, Kansas 5.6%, Arkansas 2.5%, and Oklahoma 3.2%. These percentages have not significantly changed from 2003 and 2002. Following is a description of the Company’s significant accounting policies:
Basis of Presentation
The consolidated financial statements include the accounts of The Empire District Electric Company (EDEC), and the consolidated financial statements of our wholly-owned non-regulated subsidiary, EDE Holdings, Inc. (EDE Holdings) and its subsidiaries. The consolidated entity is referred to throughout as “we” or the “Company”. On December 31, 2003 we deconsolidated the Empire District Electric Trust I in 2003 as required by Financial Accounting Standards Board (FASB) Interpretation No. 46-R (FIN 46-R).
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications had no impact on the statements of income.
Accounting for the Effects of Regulation
In accordance with Statement of Financial Accounting Standards SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).
In accordance with FAS 71, certain expenses and credits, normally recognized as incurred, are deferred as assets and liabilities on the balance sheet until the time they are recognized when recovered from or refunded to customers. As such, we have recorded certain regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. As of December 31, 2004, all of our regulatory assets are earning a current return except for approximately $9.3 million related to unamortized premiums and related costs for debt reacquired, and $2.9 million related to certain postretirement benefit costs. All of these costs were incurred prior to our 2004 rate case filings. These costs were allowed in rates in our latest Missouri rate case which was approved March 10, 2005, effective March 27, 2005. Since cost recovery of debt related costs has historically been allowed in rate cases in our other
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
jurisdictions, we expect them to be approved in our other jurisdictions as well. Postretirement benefit costs were also allowed in rates in our recently approved Missouri rate case. We believe it is probable these assets will also be afforded similar treatment by other state regulators. In addition, $2.3 million and $4.9 million of loss and gain, respectively, remaining from interest rate derivative transactions were also incurred prior to our 2004 rate case filings, and were included in the recently approved Missouri rate case. We believe it is probable they will also be included in our rate base in other states.
We continually assess the recoverability of our regulatory assets. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) 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. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.
Revenue Recognition
For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for electric services provided between the last bill date and the period end date. We also accrue a liability for the related taxes at the end of each period.
Customer information software service revenues from certain of our non-regulated operations are recognized in accordance with Statement of Position (SOP) 97-2, Software Revenue Recognition as issued by the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants (ACSEC) and related authoritative literature. Software revenue is recognized under SOP 97-2 based on the terms and conditions of each contract. Other non-regulated revenues are recognized when the manufactured products ship to the customer or when the internet or other service has been provided.
Property, Plant & Equipment
The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material and an allocation of general and administrative costs, plus an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of is charged to accumulated depreciation. Maintenance expenditures and the removal of items not considered units of property are charged to income as incurred.
Until 2002, the depreciation/cost of service methodology utilized by our rate-regulated operations included an estimated cost of dismantling and removing plant from service upon retirement. From January 2002 through March 2005, we suspended accruing the cost of removing plant from service upon retirement through depreciation rates pursuant to the October 2001 Missouri rate case. Pursuant to our latest Missouri rate case approved March 10, 2005, effective March 27, 2005, we will begin accruing cost of removal in depreciation rates for mass property (includes transmission, distribution and general plant assets) effective April 1, 2005. We reclassified the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under SFAS 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143), from accumulated depreciation to a regulatory liability. At December 31, 2004, and 2003, the amount of accrued cost of removal was $17.6 million and $17.9 million, respectively. We adjust this amount to reflect our actual cost of removal expenditures.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Depreciation
Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our non-regulated businesses are computed at straight-line rates over the estimated useful life of the properties.
The table below summarizes the total provision for depreciation and depreciation rates, both capitalized and expensed for the years ended December 31,:
The table below sets forth the average depreciation rate for each class of assets, which have been consistently applied for all periods presented:
Allowance for Funds Used During Construction
As provided in the regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to our construction program are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.
AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.
In accordance with the methodology prescribed by FERC, we utilized aggregate rates (on a before-tax basis) of 6.9% for 2004, 1.4% for 2003 and 2.4% for 2002, compounded semiannually, in determining AFUDC.
Asset Impairments
We periodically review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that there is impairment, analysis is performed based on several criteria, including but not limited to revenue trends, undiscounted forecasted cash flows and other operating factors, to determine the impairment amount. We performed this analysis at December 31, 2004
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
and 2003 and believe that no impairments exist at those dates, including assets related to our non-regulated operations. Failure to achieve forecasted cash flows could result in an impairment in the future.
Derivatives
Derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (“cash-flow” hedge); or (2) an instrument that is held for nonhedging purposes (a “non-hedging” instrument). Changes in the fair value of a derivative that is highly effective and designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are recorded in earnings). Changes in the fair value of non-hedged derivative instruments and any ineffective portion of a qualified hedge are reported in current-period earnings.
We discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer highly effective in offsetting changes in cash flows of a hedged item (including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; (3) the derivative is de-designated as a non-hedging instrument, because it is unlikely that a forecasted transaction will occur; or (4) management determines that designation of the derivative as a hedge instrument is no longer appropriate. (See Note 14.)
Pensions
Our pension expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and loses over the prior five years, with this amount being amortized over five years. In compliance with SFAS 87, “Employer’s Accounting for Pensions”, additional gain or expense may be recognized when our unrecognized gain or loss exceeds 10% of our pension benefit obligation or fair value of plan assets. In addition, we record a liability when the accumulated benefit obligation of the plan exceeds the fair value of the plan assets.
In our most recently approved Missouri Rate Case (effective March 27, 2005), the MPSC ruled the Company would be allowed to recover pension costs consistent with our GAAP policy noted above except that unrecognized actuarial gains or losses will now be amortized over a 10 year period. In accordance with the rate order, we will prospectively calculate the value of plan assets using the Market Related Value method (as defined in SFAS 87). This is a change from the policy approved in the 2002 order, which allowed us to recover pension costs on an ERISA minimum funding (or cash) basis. Prior to the 2002 order, the MPSC allowed the Company to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA recovery allowed by the MPSC and our accounting for pension costs under GAAP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, we have continued to account for pension expense or benefits in accordance with SFAS 87, using the previously mentioned amortization formula for recognizing net gains or losses. We now expect future pension expense or benefits will be fully recovered or recognized in rates charged to customers.
Postretirement Benefits
We recognize expense related to postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our expense calculation includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and losses over the prior five years with this amount being amortized over five years. Additional gain or expense may be recognized when our unrecognized gain or loss exceeds 10% of our postretirement benefit obligation or fair value of plan assets. In addition, in the third quarter, we adopted FASB staff position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”. (See “Recently Issued and Proposed Accounting Standards” below and Note 8 for more discussion.)
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.
Liability Insurance
We carry excess liability insurance for workers’ compensation and public liability claims. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. (See Note 11 for more detailed information on litigation exposure).
Franchise Taxes
Franchise taxes are collected for and remitted to their respective cities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Franchise taxes of $5,422,000, $5,142,000 and $5,464,000 were recorded for each of the years ended December 31, 2004, 2003 and 2002, respectively.
Cash & Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in accounts payable. At December 31, 2004 and 2003, these amounts were $9,957,370 and $10,232,633, respectively.
Income Taxes
Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates. (See Note 9).
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. Remaining unamortized investment tax credits are being amortized over lives ranging from 26.5 to 50.0 years.
Computations of Earnings Per Share
Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive restricted shares and options. The weighted average number of common shares outstanding used to compute basic earnings per share for the 2004, 2003 and 2002 periods were 25,467,740, 22,845,952, and 21,433,889, respectively. Additional dilutive shares for the 2004, 2003 and 2002 periods were 53,223, 7,153, and 3,821, respectively. Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company’s stock price occurs.
Stock-Based Compensation
At December 31, 2004, we had several stock-based compensation plans, which are described in more detail in Note 4. During 2002, we adopted SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of SFAS 123” (FAS 148), and elected to adopt the accounting provision of FAS 123 “Accounting for Stock-Based Compensation” (FAS 123). Under FAS 123, we recognize compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. (See further discussion in “Recently Issued and Proposed Accounting Standards” below and Note 4.)
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Asset Retirement Obligations
We account and report for legal obligations associated with the retirement or anticipated retirement of tangible long-lived assets in accordance with SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143). We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.
Upon adoption of FAS 143 on January 1, 2003, we identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant. The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. These liabilities have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. Upon adoption of this statement in the first quarter of 2003, we recorded a non-recurring discounted liability and a regulatory asset of approximately $630,000 because we expect to recover these costs of removal in electric rates either through depreciation accruals or direct expenses. This liability will be accreted over the period up to the estimated settlement date. The balances at the end of 2004 and 2003 were approximately $690,000 and $656,000, respectively. Also, we reclassified the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under FAS 143, from accumulated depreciation to a regulatory liability. This balance sheet reclassification had no impact on results of operations. As of December 31, 2004 and 2003, the accrual for cost of removal was $17.6 million and $17.9 million, respectively.
Recently Issued and Proposed Accounting Standards
In June 2004, the FASB issued an exposure draft on a proposed interpretation of SFAS No. 143, (FAS 143) “Accounting for Obligations Associated with the Retirement of Long-Lived Assets”. Under the interpretation, a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of FAS 143. Accordingly, an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be estimated reasonably. We are evaluating the effects of the proposed interpretation and cannot currently predict what effect its adoption will have on our financial condition and results of operation. This proposed interpretation, as currently drafted, would be effective for us no later than December 31, 2005.
In January 2004, FASB Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” was issued. Our postemployment medical plan provides prescription drug coverage for Medicare-eligible retirees. Our accumulated postretirement benefit obligation (APBO) and net cost recognized for other postemployment benefits (OPEB) now reflect the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act provides for a federal subsidy, beginning in 2006, of 28% of prescription drug costs between $250 and $5,000 for each Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are “actuarially equivalent” to the prescription drug benefits provided under Medicare. Equivalency must be certified annually by the Federal Government. This subsidy has caused a decrease of $6.0 million in the APBO which will be recognized as an actuarial gain and amortized through the FAS 106 post-retirement expense. We elected to defer recognition of the effects of the Act until the earlier of the issuance of final accounting guidance or a significant modification of the plan. FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the
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Medicare Prescription Drug, Improvement and Modernization Act of 2003”, was issued in May 2004 and called for the subsidy to be generally accounted for in the first annual or interim period starting after June 15, 2004. We believe that our plan provides prescription drug benefits that are “actuarially equivalent” to the prescription drug benefits provided under Medicare and will apply for certification in 2005. As a result, we adopted FASB Staff Position No. 106-2 in the third quarter of 2004, and applied it retroactively, using a measurement date of December 31, 2003. As a result, we recorded a $0.48 million credit to our FAS 106 post-retirement expense retroactive to January 1, 2004. This resulted in a reduction to our FAS 106 cost of $0.7 million in 2004.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (FAS 123R). The statement requires companies to record stock option expense in their financial statements based on a fair value methodology beginning no later than the first fiscal quarter beginning after June 15, 2005. During 2002, we adopted FAS 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of SFAS 123” (FAS 148) and elected to adopt the accounting provisions of FAS 123 “Accounting for Stock-Based Compensation” (FAS 123). Under FAS 123, we currently recognize compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. We do not expect to early adopt the provisions of FAS 123R, and do not expect it to have a material impact on our financial statements upon adoption.
In April 2003, the FASB issued SFAS No. 149 (FAS 149), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. FAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133). FAS 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30, 2003. The adoption of FAS 149 did not have a material impact on our financial condition and results of operations.
In May 2003, the FASB issued SFAS No. 150 (FAS 150), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. This statement requires that (1) financial instruments issued in the form of mandatorily redeemable shares, (2) financial instruments that, at inception, represent an obligation to repurchase the issuer’s shares or are an obligation indexed to the price of the company’s shares, and (3) financial instruments that embody an unconditional obligation, or a conditional obligation for an instrument other than an outstanding share, that the issuer must or may settle by issuing a variable number of equity shares, be classified as liabilities if, at inception, the monetary value is based on (1) a fixed amount, (2) variations in something other than the fair value of the issuer’s shares or (3) variations inversely related to the fair value of the issuer’s shares. We adopted the required provisions of FAS 150 on July 1, 2003 and the adoption did not materially impact our financial statements.
The FASB issued FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities” (FIN No. 46-R), in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46-R applied immediately to variable interest entities created after January 31, 2003. FIN No. 46-R applies to all other variable interest entities as of March 31, 2004, or, in the case of special purpose entities, December 31, 2003. Empire District Trust I, a securitization trust subsidiary of Empire created in March 2001, was consolidated within our financial statements prior to the adoption of FIN No. 46-R. As a result of the application of FIN No. 46-R, we have deconsolidated this securitization trust as of December 31, 2003. Amounts of $50 million owed to this securitization trust were recorded within the Consolidated Balance Sheet at December 31, 2004 and 2003.
In July 2003, the Emerging Issues Task Force (EITF) reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,’ and Not “Held for Trading Purposes’ as defined in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’,” (EITF 03-11) which was ratified by the FASB in August 2003 and was effective for the Company on October 1, 2003. The EITF concluded that determining whether realized
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gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The adoption of EITF 03-11 did not have an impact on our Consolidated Statements of Income.
In December 2003, the FASB issued SFAS No. 132 (revised) to improve financial statement disclosures for defined benefit plans. The standard requires more details about plan assets, benefit obligations, cash flows, benefit costs and other relevant information. SFAS No. 132 (revised) became effective for fiscal years ending after December 15, 2003. See Note 8 - Retirement Benefits for further information.
2. Property, Plant and Equipment
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3. Regulatory Matters
Rate Increases
The following table sets forth information regarding electric and water rate increases granted during the four year period ended December 31, 2004:
The 2001 Missouri electric order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later, which was collected subject to refund (with interest). The 2002 Missouri electric order called for us to refund all funds collected under the IEC, with interest, by March 15, 2003. The refunds were made in the first quarter of 2003 and did not have a material impact on our earnings in any of the years from 2001 through 2003.
On March 4, 2003, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers in the amount of $954,540, or 12.97%. On August 1, 2003, a Unanimous Stipulation and Agreement was approved by the OCC providing an annual increase in rates for our Oklahoma customers of approximately $766,500 or 10.99%, effective for bills rendered on or after August 1, 2003. This reflects a rate of return on equity (ROE) of 11.27%.
On March 17, 2003, we filed a request with the FERC for an annual increase in base rates for our on-system wholesale electric customers in the amount of $1,672,000, or 14.0%. This increase was approved by the FERC on April 25, 2003, with the new rates becoming effective May 1, 2003.
On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. As part of the filing, we asked the MPSC to consider, in addition to a traditional ratemaking approach, two options that would allow us to recover our actual fuel and purchased power expenses: an IEC, subject to refund, similar to the one approved in our 2001 case, or a fuel adjustment clause, that would reflect actual fuel prices. We subsequently abandoned our request for a fuel adjustment clause due to Missouri statutes not providing for such clauses but retained our request for the IEC, subject to refund. We also asked for a return on equity (ROE) of 11.65% and an annual increase in Missouri depreciation expense of approximately $10 million.
On May 20, 2004, we filed a request with the MPSC to implement the proposed IEC no later than June 15, 2004. However, the MPSC denied this request on August 12, 2004. On September 20, 2004, the Staff of the MPSC filed direct testimony in response to our initial April 2004 filing recommending an IEC be adopted for a period of 24 months, due to the extreme volatility currently exhibited by natural gas prices. We completed two weeks of evidentiary hearings during December 2004. Items that were covered during the hearings were: ROE, depreciation, base fuel and purchased power costs and the term and amount of an IEC. On February 22, 2005, we, the Office of Public Counsel (OPC) and two intervenors filed a Nonunanimous Stipulation and Agreement Regarding Fuel and Purchased Power Expense establishing a three year refundable IEC, which became unanimous by operation of Commission rule on March 1, 2005.
Prior to the hearings, we were able to settle several miscellaneous issues with other parties to the case. On December 22, 2004, we, the MPSC Staff, the OPC and two intervenors filed a unanimous Stipulation and Agreement
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as to Certain Issues with the MPSC settling several of these issues. One of the issues we were able to agree on was a change in the recognition of pension costs. See Note 1 - "Pensions" and Note 8 - "Retirement Benefits - Pensions"
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25.7 million, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in depreciation rates and an increase in base rates for fuel and purchased power at $24.68/MWH. In addition, the order approved an annual Interim Energy Charge (IEC) of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.0021 per kilowatt hour of customer usage. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the MPSC to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, the excess money collected from customers, if any, above $10 million of the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time. At the end of the three year term of the IEC all excess money collected from customers, if any, of the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time.
On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. Any new rates approved as a result of this request are not expected to be effective until the second quarter of 2005.
On March 2, 2005, we notified the Kansas Corporation Commission of our intent to file an application requesting a change in base rates for our Kansas electric customers. We plan to file this application in the second quarter of 2005.
Rate Matters
In accordance with FAS No. 71, we currently have deferred approximately $1,227,000 of expense related to rate cases under other non-current assets and deferred charges. $1,092,000 is directly related to the current Missouri rate case. We amortize this amount over varying periods upon the completion of the specific case. As of December 31, 2004 the full amount of the expense related to the current Missouri case is unamortized. Based on past history, we expect this expense to be recovered in rates.
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Regulatory Assets and Liabilities
We have recorded the following regulatory assets and regulatory liabilities. The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss and gain on reacquired debt and the interest rate derivatives are amortized over the life of the new debt issue, which currently ranges from 9 to 28 years.
Deregulation
Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in FAS 71 with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of FAS 71 based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations.
Federal regulation has promoted and is expected to continue to promote competition in the wholesale electric utility industry. However, none of the states in our service territory has legislation that could require competitive retail pricing to be put into effect. The Arkansas Legislature passed a bill in April 1999 that called for deregulation of the state’s electricity industry as early as January 2002. However, a law was passed in February 2003 repealing deregulation in the state of Arkansas.
Regional Transmission Organization
In December 1999, the FERC issued Order No. 2000 which encourages the development of regional transmission organizations (RTOs). RTOs are designed to independently control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive bulk power markets. On October 15, 2003, the Southwest Power Pool (SPP) announced it had filed with the FERC seeking formal recognition as an RTO in accordance with FERC Order 2000, and on February 10, 2004, the FERC approved the SPP RTO with conditions. Upon completion of the conditions, the SPP would gain status and FERC acceptance as an RTO. On October 4, 2004, the FERC granted RTO status to the SPP and ordered the SPP to resolve rate “pancaking” (accumulation of multiple access charges) concerns and assure the independence of its proposed market monitor as conditions of the decision. FERC also ordered SPP to finalize a joint operating agreement with Midwest Independent Transmission System Operator, Inc. (MISO). These conditions have been addressed and the SPP is now operating as an RTO.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We are a member of the SPP. In October 2003, we filed a notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2004 because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind such notice on or before October 31, 2004 and remain a member of the SPP, which we did on October 25, 2004. At the same time, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2005. We will be seeking authorization from Missouri, Kansas and Arkansas to participate in and transfer functional control of our transmission facilities to the SPP RTO should we decide to remain a member. As part of the applications to the aforementioned states, a formal independent SPP RTO Cost Benefit Analysis (CBA) will be submitted. It is anticipated that the completion of the CBA will be finalized by or before April 2005. We are unable to quantify the potential impact of membership in the RTO on our future financial position, results of operation or cash flows at this time, but will continue to evaluate the situation and make a decision whether or not to discontinue membership with the SPP.
4. Common Stock
New Issuances
On December 17, 2003, we sold 2,000,000 shares of our common stock in an underwritten public offering for $21.15 per share. On January 8, 2004, we sold an additional 300,000 shares to cover the underwriters’ over-allotments. The December sale resulted in proceeds of approximately $40,275,000, net of issuance costs of $2,025,000. The January sales resulted in proceeds of approximately $6,075,000 net of issuance costs.
On May 22, 2002, we sold 2,500,000 shares of our common stock in an underwritten public offering for $20.75 per share. This sale resulted in proceeds of approximately $49,433,000, net of issuance costs of $2,442,000.
Stock-Based Awards and Programs
We have several stock based awards and programs, which are described below. During 2002, we adopted SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of SFAS 123” (FAS 148), and elected to adopt the accounting provision of FAS 123 “Accounting for Stock-Based Compensation”. Under FAS 123, we recognize compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. This applies to our employee stock purchase plan and our stock incentive plan.
Stock compensation expense relative to all of our stock based awards and programs was approximately $2.1 million, $1.1 million, and $1.0 million in 2004, 2003, and 2002, respectively.
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. There are 100,953 shares available for issuance in this plan.
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Stock Incentive Plan
Our 1996 Incentive Plan (the Stock Incentive Plan) provides for the grant of up to 650,000 shares of common stock through January 2006. The Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director. The number of shares issued to directors in lieu of fees were:
The terms and conditions of any option or stock grant are determined by the Board of Directors’ Compensation Committee, within the provisions of the Stock Incentive Plan. The other components of this Stock Incentive Plan are described below. At December 31, 2004, there were 610,547 shares available for issuance under this plan.
Stock Incentive Plan - Restricted Stock Awards
During February 2002 and February 2001, awards of restricted stock were made to qualified employees under the Stock Incentive Plan. For grants made to date, the restrictions typically lapse and the shares are issuable to employees who continue in service with us three years from the date of grant. For employees whose service is terminated by death, retirement, disability, or under certain circumstances following a change in control of the Company prior to the restrictions lapsing, the shares are issuable immediately upon such termination. For other terminations, the grant is forfeited. No restricted shares were granted in 2004 or 2003 nor are any expected to be granted in future periods.
Stock Incentive Plan - Performance-Based Restricted Stock Awards
Beginning in 2002, performance-based restricted stock awards were granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group.
Stock Incentive Plan - Stock Options
Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire ten years after the date granted. Participants’ options that are not vested become forfeited when participants leave Empire except for terminations of employment under certain specified circumstances. Dividend equivalent awards were also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes exercisable and will then be converted to restricted shares of our common stock based on the fair market value of the shares on the date converted. Such restricted shares vest on the eighth anniversary of the grant of the dividend equivalent award or, if earlier, upon exercise of the related option in full. The restricted shares are subject to forfeiture if the related option terminates without having been exercised in full prior to the vesting of these shares.
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Presented below is a summary of stock option plan activity for the years shown:
The range of exercise prices for the options outstanding at December 31, 2004 was $18.25 to $21.79. The weighted-average remaining contractual life of outstanding options at December 31, 2004 and 2003 was 8.1 years and 8.6 years, respectively. The fair value of the options granted, which is amortized to expense over the option vesting period, has been determined on the date of grant using the Expanded Black-Scholes option-pricing model with the following assumptions:
(1)
Reflects the existence of dividend equivalents.
Stock Unit Plan for Directors
Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based retirement compensation program for Directors. This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate retirement benefits in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. As of December 31, 2004, all eligible Directors who had benefits under the prior cash retirement plan have converted their cash retirement benefits to common stock units.
A total of 200,000 shares are authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock upon retirement by the Director. The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend’s record date. We record the related compensation expense at the time we make the accrual for the Directors’ retirement benefits as the Directors provide services. At December 31, 2004 there were 58,528 shares accrued to Directors’ accounts and 164,266 shares available for issuance under this plan.
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401(k) Plan and ESOP
Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. We match 50% of each employee’s deferrals by contributing shares of our common stock, such matching contributions not to exceed 3% of the employee’s eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2004 there were 186,091 shares available to be issued.
Dividends
Holders of our common stock are entitled to dividends, if, as and when declared by our Board of Directors out of funds legally available therefore subject to the prior rights of holders of our outstanding cumulative preferred and preference stock. Our indenture of mortgage and deed of trust governing our first mortgage bonds restricts our ability to pay dividends on our common stock. In addition, under certain circumstances (including defaults thereunder), Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock.
5. Preferred and Preference Stock
We have 2,500,000 shares of preference stock authorized, including 500,000 shares of Series A Participating Preference Stock, none of which have been issued. We have 5,000,000 shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2004 or 2003.
Preference Stock Purchase Rights
Our shareholder rights plan provides each of the common stockholders one Preference Stock Purchase Right (“Right”) for each share of common stock owned. Each Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one one-hundredth share, subject to adjustment. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire July 25, 2010, will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. The Rights may be redeemed by us in whole, but not in part, for $0.01 per Right, prior to 10 days after the first public announcement of the acquisition of 10% or more of our common stock by an Acquiring Person. We had 25,637,443 and 24,915,722 Rights outstanding at December 31, 2004 and 2003, respectively.
In addition, upon the occurrence of a merger or other business combination, or an event of the type referred to in the preceding paragraph, holders of the Rights, other than an Acquiring Person, will be entitled, upon exercise of a Right, to receive either our common stock or common stock of the Acquiring Person having a value equal to two times the exercise price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of our outstanding common stock, our Board of Directors may, at their option, exchange part or all of the Rights (other than Rights held by the Acquiring Person) for our common stock on a one-for-one basis.
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6. Long-Term Debt
At December 31, 2004 and 2003 the balance of long-term debt outstanding was as follows:
(3)
We may redeem some or all of the notes at any time at 100% of their principal amount, plus accrued and unpaid interest to the redemption date.
(4)
We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
On March 1, 2001, Empire District Electric Trust I (Trust) issued 2,000,000 shares of its 8-1/2% Trust Preferred Securities (liquidation amount $25 per preferred security) in a public underwritten offering. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8-1/2% of the $25 per share liquidation amount. Quarterly payments of dividends by the trust, as well as payments of principal, are made from cash received
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from corresponding payments made by us on $50,000,000 aggregate principal amount of 8-1/2% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust and held by the trust as assets. Interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The Junior Subordinated Debentures are shown as “Note payable to securitization trust” on our balance sheet. In connection with the deconsolidation, we recorded our $1,550,000 investment in the Trust and a corresponding note payable to the Trust for the investment.
As discussed above, at January 1, 2005, EDE Holdings is the guarantor for 50.01% of a $2.7 million note issued by Mid-America Precision Products (MAPP). This is fully consolidated in our balance sheet as EDE Holdings owns 50.01% of MAPP. EDE Holdings also guarantees 50.01% of MAPP’s revolving short-term credit facility of $0.85 million, of which $0.8 million is outstanding at year end and consolidated within our financial statements. We have no other guarantees.
The principal amount of all series of first mortgage bonds outstanding at any one time is limited by terms of the mortgage to $1,000,000,000. Substantially all of The Empire District Electric Company’s property, plant and equipment is subject to the lien of the mortgage. The indenture governing our first mortgage bonds contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the mortgage) for any twelve consecutive months within the 15 months preceding issuance must be two times the annual interest requirements (as defined in the mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended December 31, 2004 would permit us to issue $172.2 million of new first mortgage bonds based on this test, with an assumed interest rate of 7%. In addition to the interest coverage requirement, the mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2004, we had retired bonds and net property additions which would enable the issuance of at least $401.1 million principal amount of bonds if the annual interest requirements are met. We are in compliance with all restrictive covenants of our first mortgage bonds debt agreements.
On December 23, 2002, we sold to the public in an underwritten offering $50 million aggregate principal amount of our unsecured Senior Notes, 7.05% Series due 2022 which mature on December 15, 2022. The net proceeds of approximately $48.6 million were added to our general funds and used to repay short-term debt.
On June 17, 2003, we sold to the public in an underwritten offering, $98 million aggregate principal amount of our unsecured Senior Notes, 4.5% Series due 2013, for net proceeds of approximately $96.6 million. We used the net proceeds from this issuance, along with short-term debt, to redeem all $100 million aggregate principal amount of our Senior Notes, 7.70% Series due 2004 for approximately $109.8 million, including interest. We had entered into an interest rate derivative contract in May 2003 to hedge against the risk of a rise in interest rates impacting the 2013 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $2.7 million and were capitalized as a regulatory asset and are being amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the Senior Notes, 7.70% Series due 2004.
On November 3, 2003, we issued $62.0 million aggregate principal amount of Senior Notes, 6.70% Series due 2033 for net proceeds of approximately $61.0 million. We used the proceeds from this issuance, along with short-term debt, to redeem three separate series of our outstanding first mortgage bonds: (1) all $2.25 million aggregate principal amount of our First Mortgage Bonds, 9-3/4% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7-1/4% Series due 2028 for approximately $13.7 million, including interest; and (3) all $45.0 million aggregate principal amount of our First Mortgage Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the risk of a rise in interest rates impacting the 2033 Notes prior to their issue. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and is being amortized over the life of the debt to reduce interest expense.
The carrying amount of our total debt exclusive of capital leases was $411,150,250 and $411,518,633 at December 31, 2004 and 2003, respectively, and its fair market value was estimated to be approximately $425,235,358 and $421,074,341, respectively. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.
Payments Due by Period (in millions)
7. Short-term Borrowings
Short-term commercial paper outstanding and notes payable averaged $1,423,497 and $42,842,666 daily during 2004 and 2003 respectively, with the highest month-end balances being $8,500,000 and $74,350,000, respectively. The weighted average interest rates during 2004 and 2003 was 1.4% in each period. The weighted average interest rates of borrowings outstanding at December 31, 2003 were 1.4%. At December 31, 2004, we had no commercial paper outstanding.
On October 22, 2004, we extended our $100 million unsecured revolving credit facility until May 31, 2006. Borrowings are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. The credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2004, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $5,000,000 in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at December 31, 2004 and 2003.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Retirement Benefits
Pensions
Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service and the employee’s average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding requirements of ERISA. Plan assets consist of common stocks, United States government obligations, federal agency bonds, corporate bonds and commingled trust funds.
We expect there will be no contribution required under ERISA in order to maintain minimum funding levels in 2005. This could change, however, based on actual investment performance, any future pension plan funding and finalization of actuarial assumptions. At December 31, 2004, there was no minimum pension liability required to be recorded.
Our pension expense or benefit includes amortization of previously unrecognized actuarial net gains or losses. Through 2004, the amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years subject to minimum amortization requirements in accordance with the provisions of SFAS 87, “Employers’ Accounting for Pensions” (FAS 87). Pursuant to the 2004 Missouri rate case, approved March 10, 2005, these gains or losses will be amortized over a 10 year period. Also, in accordance with the rate order, we will prospectively calculate the value of plan assets using the Market Related Value method (as defined in FAS 87). This is a change from the policy approved in our 2002 order. As a result of the approved order, we expect our future pension expense to be fully recovered or recognized in rates charged to customers.
Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates), and employee compensation trend rates.
Our expected benefit payments from our pension trust, (in millions) are as follows:
The following table sets forth the plan’s projected benefit obligation, the fair value of the plan’s assets and its funded status:
Reconciliation of Projected Benefit Obligations:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Reconciliation of Fair Value of Plan Assets:
Reconciliation of Funded Status:
At December 31, 2004, our accumulated benefit obligation was $94,850,123 and our plan asset value was $95,900,778. Therefore, a minimum pension liability has not been recorded.
Net Periodic Pension Benefit Cost/(Income)
Our net periodic benefit cost/(income), (related to the application of FAS 87), net of tax, as a percentage of net income for 2004, 2003 and 2002, was 6.80%, 6.59% and (6.87%), respectively.
Net periodic benefit pension cost/(income), some of which is capitalized as a component of labor cost, for 2004, 2003 and 2002, is comprised of the following components:
Assumptions used to determine Year End Benefit Obligation
Assumptions used to determine Net Periodic Pension Benefit Cost/(Income)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The expected long-term rate of return assumption was based on historical returns and adjusted to estimate the potential range of returns for the current asset allocation.
Allocation of Plan Assets
We utilize fair value in determining the market-related values for the different classes of our pension plan assets.
The Company’s primary investment goals for pension fund assets are based around four basic elements:
2.
Maintain a minimum level of return equal to the actuarial interest rate assumption,
3.
Maintain a high degree of flexibility and a low degree of volatility, and
4.
Maximize the rate of return while operating within the confines of prudence and safety.
The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund’s principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored on a quarterly basis by the Company’s Investment Committee.
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Equity
Fixed Income
· Common Stocks
· Preferred Stocks
· Convertible Preferred Stocks
· Convertible Bonds
· Covered Options
· Bonds
· GICs, BICs
· Cash-Equivalent Securities (e.g., U.S. T-Bills,
Commercial Paper, etc.)
· Certificates of Deposit in institutions with
FDIC/FSLIC protection
· Money Market Funds/Bank STIF Funds
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Those investments prohibited by the Investment Committee without prior approval are:
· Privately Placed Securities
· Commodities Futures
· Securities of Empire District
· Derivatives
· Warrants
· Short Sales
· Index Options
Other Postretirement Benefits
We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.
Effective January 1, 1993, we adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (FAS 106), which requires recognition of these benefits on an accrual basis during the active service period of the employees. We elected to amortize our transition obligation (approximately $21,700,000) related to FAS 106 over a twenty-year period. Prior to adoption of FAS 106, we recognized the cost of such postretirement benefits on a pay-as-you-go (i.e., cash) basis. The states of Missouri, Kansas, Oklahoma and Arkansas authorize the recovery of FAS 106 costs through rates.
In accordance with rate orders, we established two separate trusts in 1994, one for those retirees who were subject to a collectively bargained agreement and the other for all other retirees, to fund retiree healthcare and life insurance benefits.
In addition, we adopted FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, in the third quarter of 2004.We applied it retroactively, using a measurement date of December 31, 2003. Our postemployment medical plan provides prescription drug coverage for Medicare-eligible retirees. Our accumulated postretirement benefit obligation (APBO) and net cost recognized for other postemployment benefits (OPEB) now reflect the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy, beginning in 2006, of 28% of prescription drug costs between $250 and $5,000 for each Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are “actuarially equivalent” to the prescription drug benefits provided under Medicare. We have determined that our plan provides benefits that are actuarially equivalent to the benefits provided under Medicare and will apply for certification in 2005. This adoption resulted in a reduction to our FAS 106 cost of $0.7 million in 2004.
Our funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefit costs allowed in rates. Based on the performance of the trust assets through December 31, 2004, we expect to be required to fund approximately $6 million in 2005. Assets in these trusts amounted to approximately $33.1 million at December 31, 2004, $27.9 million at December 31, 2003 and $21.5 million at December 31, 2002.
Our estimated benefit payments from trust assets (in millions) are as follows:
Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), health care cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the plan’s benefit obligation, the fair value of the plan’s assets and its funded status:
Reconciliation of Benefit Obligation:
Reconciliation of Fair Value of Plan Assets:
Reconciliation of Funded Status:
Postretirement benefit cost, a portion of which has been capitalized for 2004, 2003 and 2002, is as follows:
Net Periodic Postretirement Benefit Cost:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(3)
2004 reflects the effect of the Medicare Act subsidy which resulted in a decrease of $6.0 million in the APBO for the past service cost. This was recognized as an actuarial gain and will be amortized through the FAS 106 postretirement expense.
(4)
Total 2004 cost reflects the impact of the Medicare Act subsidy on the net periodic postretirement benefit cost as follows:
Assumptions used to determine Year End Benefit Obligation
Assumptions used to determine Net Periodic Benefit Cost
The expected long-term rate of return assumption was based on historical returns and adjusted to estimate the potential range of returns for the current asset allocation.
The assumed 2004 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 9.5%. Each trend rate decreases 0.50% through 2014 to an ultimate rate of 5% for 2014 and subsequent years.
The effect of a 1% increase in each future year’s assumed healthcare cost trend rate would increase the current service and interest cost from $4.8 million to $5.8 million and the accumulated postretirement benefit obligation from $60.4 million to $68.9 million. The effect of a 1% decrease in each future year’s assumed healthcare cost trend rate would decrease the current service and interest cost from $4.8 million to $4.1 million and the accumulated benefit obligation from $60.4 million to $53.4 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Allocation of Plan Assets
We utilize fair value in determining the market-related values for the different classes of our postretirement plan assets.
The Company’s primary investment goals for the component of the fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return.
The Company’s guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored on a quarterly basis by the Company’s Investment Committee.
Permissible Investments:
Listed below are the investment vehicles specifically permitted:
Equity
Fixed Income
· Common Stocks
· Preferred Stocks
· Bonds
· Cash-Equivalent Securities with a maturity of one year or less
· Bonds
· Money Market Funds
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
Those investments prohibited by the Investment Committee are:
· Privately Placed Securities
· Commodities Futures
· Securities of Empire District
· Derivatives
· Instrumentalities in violation of the
Prohibited Transactions Standards of ERISA
· Margin Transactions
· Short Sales
· Index Options
· Real Estate and Real Property
· Restricted Stock
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Income Taxes
The provision for income taxes is different from the amount of income tax determined by applying the statutory income tax rate to income before income taxes as a result of the following differences:
Income tax expense components for the years shown are as follows:
Total income tax expense is shown on more than one tax line on the income statement.
Under SFAS No. 109, “Accounting for Income Taxes” (FAS 109), temporary differences gave rise to deferred tax assets and deferred tax liabilities at December 31, 2004 and 2003 as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The net of the deferred tax assets and liabilities above are presented as deferred income taxes under non current liabilities on the balance sheet.
10. Commonly Owned Facilities
We own a 12% undivided interest in the Iatan Power Plant, a coal-fired, 670-megawatt generating unit near Weston, Missouri. Kansas City Power & Light and Aquila own 70% and 18%, respectively, of the Unit. We are entitled to 12% of the available capacity and are obligated for that percentage of costs included in the corresponding operating expense classifications in the Statement of Income. At December 31, 2004 and 2003, our property, plant and equipment accounts included the cost of our ownership interest in the plant of $49,197,000 and $48,915,000, respectively, and accumulated depreciation of $34,510,000 and $33,259,000, respectively. Expenditures recorded for our portion of ownership were $6,786,000 and $7,319,000 for 2004 and 2003, respectively, excluding depreciation expenses.
On July 26, 1999, we and Westar Generating, Inc. (“WGI”), a subsidiary of Westar Energy, Inc., entered into agreements for the construction, ownership and operation of a 500-megawatt combined cycle unit at the State Line Power Plant (the “State Line Combined Cycle Unit”). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs. At December 31, 2004 and 2003, our property, plant and equipment accounts include the cost of our ownership interest in the unit of $153,334,000 and $153,243,000, respectively, and accumulated depreciation of $18,108,000 and $13,847,000, respectively. Expenditures recorded for our portion of ownership were $34,886,000 and $24,700,000 for 2004 and 2003, respectively, excluding depreciation.
11. Commitments and Contingencies
We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5). In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of operations or cash flows.
Coal, Natural Gas and Transportation Contracts
We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply. Under these contracts, the natural gas supplies are divided into firm physical commitments and options that are used to hedge future purchases. The firm physical gas commitments, which represent normal purchases and sales, and transportation commitments total $19.4 million for 2005, $23.0 million for 2006 through 2007, $23.3 million for 2008 through 2009 and $65.6 million for 2010 and beyond. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price.
We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements are $17.1 million for 2005, $16.5 million for 2006 through 2007, and $0.9 million for 2008 through 2009.
Purchased Power
We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $87.7 million through May 31, 2010.
On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed 150-megawatt Elk River Windfarm located in Butler County, Kansas. We anticipate purchasing approximately 550,000 megawatt-hours of energy annually from the project beginning in December 2005. We will not own any portion of the windfarm. Costs for energy purchased under this agreement will be expensed as incurred. On January 24, 2005, Flint Hills Tallgrass Prairie Heritage Foundation, Inc. filed a purported class action complaint in the United States District Court (the Court) seeking to halt the development or operation of industrial wind turbine electric power generation facilities within the Flint Hills Tallgrass Prairie Ecosystem. This complaint was dismissed with prejudice by the Court on February 11, 2005. A notice of appeal has been filed.
Environmental Matters
We are subject to various federal, state, and local laws and regulations with respect to air and water quality as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.
Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan Power Plants and Units 3 and 4, the FT8 peaking units, at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx). When a plant becomes an affected unit for a particular emission, it locks in the then current emission standards. The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003.
SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been awarded a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances may be traded between plants or utilities or “banked” for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (EPA) withholds annually a percentage of the emission allowances awarded to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these allowances.
In 2004, our Asbury, Riverton and Iatan plants burned a blend of low sulfur Western coal (Powder River Basin) and higher sulfur local coal or burned 100% low sulfur Western coal. In addition, tire derived fuel (TDF) was used as a supplemental fuel at the Asbury plant. The Riverton plant can also burn natural gas as its primary fuel. The State Line Plant and the Energy Center Units 3 and 4 are gas-fired facilities and do not receive SO2 allowances. Annual allowance requirements for the State Line Plant and the Energy Center Units 3 and 4, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. Based on current operations, the combined actual SO2 allowance need for all affected plant facilities is approximately equal to the number of allowances awarded to us annually by the EPA. As of December 31, 2004, we currently have 48,000 banked allowances.
On July 14, 2004, we filed an application with the Missouri Public Service Commission seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of our SO2 emission allowances. Subsequently, we, the Missouri Public Service Commission Staff (Staff) and the Office of Public Counsel (OPC) engaged in discussions to determine an agreeable manner for us to implement an SO2
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Allowance Management Policy (SAMP). As a result of these discussions, the parties entered into a Unanimous Stipulation and Agreement on January 18, 2005, stating that we should be granted authority by the Commission to manage our SO2 allowance inventory in accordance with the terms in our SAMP document, which would provide us the authority to swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, provides us with the authority to sell SO2 allowances outright for monetary value. On March 1, 2005, the Missouri Public Service Commission approved the Stipulation and Agreement to become effective March 11, 2005.
NOx Emissions. The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated.
The Asbury Plant received permission from the Missouri Department of Natural Resources (MDNR) to burn TDF at a maximum rate of 2% of total fuel input. During 2004, approximately 9,550 tons of TDF were burned.
In April 2000 the MDNR promulgated a final rule addressing the ozone moderate non-attainment classification of the St. Louis area. The final regulation, known as the Missouri NOx Rule, set a maximum NOx emission rate of 0.25 lbs/mmBtu for Eastern Missouri and a maximum NOx emission rate of 0.35 lbs/mmBtu for Western Missouri. The Iatan, Asbury, State Line and Energy Center facilities are affected by the Western Missouri regulation. In April 2003 the MDNR approved amendments to the Missouri NOx Rule. Included were amendments to delay the effective date of the rule until May 1, 2004 and to establish a NOx emission limit of 0.68 lbs/mmBtu for plants burning tire derived fuel with a minimum annual burn of 100,000 passenger tire equivalents. The Asbury Plant qualified for the 0.68 lbs/mmBtu emission rate. All of our plants currently meet the required emission limits and additional NOx controls are not required.
Water. We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line facilities are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The Energy Center permit was revised in 2004. The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the CWA 316 (b) Phase II. The regulations became final on February 16, 2004 and require the submission of a Comprehensive Demonstration Study with the permit renewal in 2008. The costs associated with compliance with these regulations are not expected to be material.
Other. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site’s total emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Power Plants. We submitted the required renewal application for the Asbury Title V permit in 2004 and will operate under the existing permit until the MDNR issues the renewed permit. A Compliance Assurance Monitoring (CAM) plan is expected to be required by the renewed permit. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.
In mid-December 2003, the EPA issued proposed regulations with respect to SO2, NOx and mercury emissions from coal-fired power plants in a proposed rulemaking known as the Clean Air Interstate Rule (CAIR). The final CAIR was issued by the EPA on March 10, 2005 and will affect 28 states, including Missouri, where our Asbury plant is located, but excluding Kansas, where our Riverton plant is located. Also in mid-December 2003, the EPA issued proposed regulations for mercury emissions by power plants under the requirements of the 1990 Amendments. These proposed regulations are currently expected to be finalized in March 2005. It is possible that we may need to make some expenditures as early as 2005 in order to meet a proposed December 15, 2007 requirement for anticipated mercury reduction requirements under the proposed clean air mercury regulations. The CAIR was issued, and the clean air mercury regulations are expected to be issued, as a result of delays and setbacks in the legislative process for the President’s Clear Skies Act legislation, which would have imposed different restrictions on SO2, NOx and mercury emissions. The CAIR is not directed to specific generation units, but instead,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
requires the state of Missouri to develop a State Implementation Plan (SIP) within the next 18 months in order to comply with specific NOx and SO2 state-wide annual budgets. Until that plan is finalized, we cannot determine the required emission rate of NOx and SO2 for the Asbury or Iatan plants. Also, the SIP will likely include an allowance trading program for NOx and SO2 that could provide compliance without additional capital expenditures. Until the proposed mercury regulations are finalized and additional testing for mercury emissions is completed at Iatan, Asbury and Riverton, we cannot determine if additional investments are required. It is possible that compliance with the proposed mercury regulations will not require additional capital expenditures. However, we expect that pollution control equipment required at the Iatan plant by 2015 may include a Selective Catalytic Reduction (SCR) system and a Flue Gas Desulphurization (FGD) system and a Bag House, with our share of the capital cost estimated at $30 million. We expect that pollution control equipment needed at the Asbury plant by 2015 may include a SCR, a FGD and a Bag House at an estimated capital cost of $80 million.
12. Non-regulated Businesses
On July 17, 2002, EDE Holdings, Inc., together with other investors, acquired the assets of the Precision Products Department of Eagle Picher Technologies, LLC, a manufacturer of close-tolerance metal products whose customers are in the aerospace, electronics, telecommunications, and machinery industries. The acquisition was accomplished through the creation of a newly formed, non-regulated limited liability company, Mid-America Precision Products (MAPP). EDE Holdings acquired a controlling 50.01% interest in this newly formed company through a cash investment of $650,000. As of January 1, 2005, EDE Holdings is also the 50.01% guarantor of a $2.7 million long-term note payable and a $0.8 million revolving short-term credit facility. The acquisition was accounted for using the purchase method of accounting in accordance with SFAS No. 141, “Business Combinations” (FAS 141). Current assets were valued based on the carrying value at July 17, 2002. The property, plant and equipment was valued through a third party appraisal. The change in non-regulated revenues, expenses and minority interest for the year ended December 31, 2003 compared to the year ended December 31, 2002, reflect a full year’s results of this acquisition.
In the first half of 2003, we began amortizing the accumulated costs for our Conversant software and the value of the customer list obtained with our purchase of Joplin.com. This amortization was $237,000 and $171,000 in 2004 and 2003, respectively.
The table below presents information about the reported revenues, operating income, net income, capital expenditures, total assets and minority interests of our non-regulated businesses.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
*
Non-Regulated numbers include revenues received from the regulated business that are eliminated in consolidation.
13. Selected Quarterly Information (Unaudited)
The following is a summary of previously reported and adjusted quarterly results for 2004 and reported quarterly results for 2003. We adopted FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, in the third quarter of 2004. and applied it retroactively, using a measurement date as of December 31, 2003. The effect of this adoption on our total net periodic postretirement benefit cost was $0.7 million for the year. The first and second quarterly results originally reported, did not include the after tax effect on earnings of $0.1 million per quarter.
The sum of the quarterly earnings per share of common stock may not equal the earnings per share of common stock as computed on an annual basis due to rounding.
14. Risk Management and Derivative Financial Instruments
We utilize derivatives to manage our natural gas commodity market risk to help manage our exposure resulting from purchasing natural gas, to be used as fuel, on the volatile spot market and to manage certain interest rate exposure.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2004 and 2003, we have recorded the following assets and liabilities representing the fair value of qualifying derivative financial instruments held as of that date and subject to the reporting requirements of FAS 133.
A $2,774,221 net of tax, unrealized gain representing the fair market value of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The tax effect of $1,700,329 on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning January 1, 2005 and ending on September 30, 2011. At the end of each determination period, any gain or loss for that period related to the instrument will be reclassified to fuel expense.
In the first quarter of 2003, we began recording unrealized gains/(losses) on the overhedged portion of our gas hedging activities in “Fuel” under the Operating Revenue Deductions section of our income statements since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. We had previously recorded such gains/(losses), which were not material in the prior periods ended December 31, 2002, in “Other - non-operating income” under the Other Income and Deductions section.
The following table sets forth “mark-to-market” pre-tax gains/(losses) from the overhedged portion of our hedging activities and the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel” (in millions):
The table above does not include a $5.1 million realized gain from an interest rate derivative contract in November 2003 or a $2.7 million realized loss from an interest rate derivative contract in June 2003. The benefit and cost of these transactions are recorded as interest expense as amortized. See Note 6 “Long-Term Debt” for information on our hedging of interest rate exposures.
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases and normal sales (NPNS). We have instituted a process to determine if any future executed contracts that otherwise qualify for the NPNS exception contain a price adjustment feature and will account for these contracts accordingly.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Accounts Receivable - Other
The following table sets forth the major components comprising “accounts receivable - other” on our consolidated balance sheet (in millions):
(2)
The increase to $3.1 million in accounts receivable of our non-regulated subsidiary companies is due mainly to increased trade receivables for Mid-America Precision Products, LLC (MAPP).
16. Regulated - Other Operating Expense
The following table sets forth the major components comprising “regulated - other” under “Operating Revenue Deductions” on our consolidated statements of income (in millions) for all periods presented:
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information to be required to be disclosed by us in reports that we file or submit under the Exchange Act.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item with respect to directors and directorships, our audit committee, our audit committee financial experts and Section 16(a) Beneficial Ownership Reporting Compliance may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2005, which is incorporated herein by reference.
Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under “Executive Officers and Other Officers of Empire.”
We have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. A copy of this code is available on our website at www.empiredistrict.com. No amendments to the code have been made and no waivers of the code have been granted since its adoption. Any future amendments or waivers to the code will be posted on our website at www.empiredistrict.com.
Because our common stock is listed on the NYSE, our Chief Executive Officer is required to make a CEO’s Annual Certification to the NYSE in accordance with Section 303A.12 of the NYSE Listed Company Manual stating that he is not aware of any violations by us of the NYSE corporate governance listing standards. Our Chief Executive Officer intends to timely provide the NYSE with the CEO’s Annual Certification and we will make this certification available on our website, www.empiredistrict.com, as soon as reasonably practicable after filing with the NYSE.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2005, which is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the number of shares of our equity securities owned by persons who own beneficially more than 5% of our voting securities and beneficially owned by our directors and certain executive officers and by the directors and executive officers as a group may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2005, which is incorporated herein by reference.
There are no arrangements the operation of which may at a subsequent date result in a change in control of Empire.
Securities Authorized For Issuance Under Equity Compensation Plans
We have two equity compensation plans approved by shareholders, the 1996 Stock Incentive Plan and the Employee Stock Purchase Plan, and one equity compensation plan not approved by shareholders (because approval was not required), the Stock Unit Plan for Directors.
The following table summarizes information about our equity compensation plans as of December 31, 2004.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item with respect to certain relationships and related transactions may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2005, which is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item with respect to principal accountant fees and services may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 28, 2005, which is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Index to Financial Statements and Financial Statement Schedule Covered by
Report of Independent Auditors
All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial statements or notes thereto.
List of Exhibits
 This exhibit is a compensatory plan or arrangement as contemplated by Item 15(a)(3) of Form 10-K.
* Filed herewith
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 2004, 2003 and
NOTE A: This reserve is provided for workers’ compensation, certain postemployment benefits and public liability damages. At December 31, 2004, we carried insurance for workers’ compensation claims in excess of $500,000 and for public liability claims in excess of $500,000. The injuries and damages reserve is included on the Balance Sheet in the section “Noncurrent liabilities and deferred credits” in the category “Other”.
SIGNATURES
Pursuant to the requirements of Section 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.
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 date indicated.