UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
x | | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2005 or
o | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from to .
Commission file number: 1-3368
THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Kansas | | 44-0236370 |
(State of Incorporation) | | (I.R.S. Employer Identification No.) |
602 Joplin Street, Joplin, Missouri | | 64801 |
(Address of principal executive offices) | | (zip code) |
Registrant’s telephone number: (417) 625-5100
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | | Name of each exchange on
which registered |
Common Stock ($1 par value) | | New York Stock Exchange |
Preference Stock Purchase Rights | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):
Large accelerated filer o | | Accelerated filer x | | Non-accelerated filer o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The aggregate market value of the registrant’s voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock Exchange on June 30, 2005, was approximately $621,489,096.
As of March 1, 2006, 26,136,318 shares of common stock were outstanding.
The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:
The Company’s proxy statement, filed pursuant | | Part of Item 10 of Part III |
to Regulation 14A under the Securities Exchange | | All of Item 11 of Part III |
Act of 1934, for its Annual Meeting of | | Part of Item 12 of Part III |
Stockholders to be held on April 27, 2006. | | All of Item 13 of Part III |
| | All of Item 14 of Part III |
FORWARD LOOKING STATEMENTS
Certain matters discussed in this annual report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate,” “believe,” “expect,” “project,” “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:
· the amount, terms and timing of rate relief we seek and related matters;
· the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;
· electric utility restructuring, including ongoing state and federal activities;
· weather, business and economic conditions and other factors which may impact customer growth;
· operation of our generation facilities;
· legislation;
· regulation, including environmental regulation (such as NOx regulation);
· competition;
· the impact of deregulation on off-system sales;
· changes in accounting requirements;
· other circumstances affecting anticipated rates, revenues and costs, including pension and post-retirement costs;
· the timing of, accretion estimates, and integration costs relating to, contemplated acquisitions and the performance of acquired businesses;
· matters such as the effect of changes in credit ratings on the availability and cost of funds;
· the periodic revision of our construction and capital expenditure plans and cost estimates;
· the performance and liquidity needs of our non-regulated businesses;
· the success of efforts to invest in and develop new opportunities; and
· costs and effects of legal and administrative proceedings, settlements, investigations and claims.
All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.
We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.
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PART I
ITEM 1. BUSINESS
General
The Empire District Electric Company, a Kansas corporation organized in 1909, 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. In 2005, 92.9% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.7% from our non-regulated businesses. We operate our business in two segments, regulated and other, which includes our non-regulated businesses.
The territory served by our electric operations embraces an area of about 10,000 square miles with a population of over 450,000. The service territory is located principally in southwestern Missouri and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal activities of these areas include light industry, agriculture and tourism. Of our total 2005 retail electric revenues, approximately 88.8% came from Missouri customers, 5.2% from Kansas customers, 3.1% from Oklahoma customers and 2.9% from Arkansas customers.
We supply electric service at retail to 121 incorporated communities and to various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 157,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 50% of our electric operating revenues in 2005 were derived from incorporated communities with franchises having at least ten years remaining and approximately 19% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.
Our electric operating revenues in 2005 were derived as follows: residential 41.6%, commercial 29.6%, industrial 16.6%, wholesale on-system 4.6%, wholesale off-system 3.9% and other 3.7%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2005 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 2% of electric revenues in 2005.
Our other segment 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), provision of Internet access, close-tolerance custom manufacturing and customer information system software services. See Item 2, “Properties — Other” for further information about our non-regulated businesses.
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price, originally $84 million in cash, plus working capital and subject to net plant adjustments, was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila will retain certain liabilities and obligations originally to have been assumed by us. We expect the acquisition to be financed with a mix of debt and equity and to be accretive to earnings in the range of $0.04 to $0.07 per year, excluding transition costs, beginning in its first full year of operations. This transaction is subject to the approval of the Missouri Public Service Commission (MPSC) and other customary closing conditions. We filed an application with the MPSC on November 8, 2005 seeking approval and anticipate closing the
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transaction in mid 2006. We received notice of early termination of the Hart-Scott-Rodino Antitrust Improvements Act waiting period in January 2006. On March 1, 2006, we, Aquila Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting they approve the proposed transaction.
Electric Generating Facilities and Capacity
At December 31, 2005, our generating plants consisted of:
Plant | | | *Capacity
(megawatts) | | Primary Fuel | |
Asbury | | | 210 | | | Coal | |
Riverton | | | 136 | | | Coal | |
Iatan (12% ownership) | | | 80 | | | Coal | |
State Line Combined Cycle (60% ownership) | | | 300 | | | Natural Gas | |
Empire Energy Center | | | 271 | | | Natural Gas | |
State Line Unit No. 1 | | | 89 | | | Natural Gas | |
Ozark Beach | | | 16 | | | Hydro | |
Total | | | 1,102 | | | | |
* based on summer rating conditions as utilized by SPP.
See Item 2, “Properties — Electric Facilities” for further information about these plants.
We, and most other electric utilities with interstate transmission facilities, have placed our facilities under the Federal Energy Regulatory Commission (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. We have, however, filed a notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2006. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Competition.”
We currently supplement our on-system generating capacity with purchases of capacity and energy from other sources 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 rules. The SPP requires its members to maintain a minimum 12% capacity margin. We have contracted with Westar Energy for the purchase of 162 megawatts of capacity and energy through May 31, 2010 and intend to add another 50 megawatts of purchased power in 2010 from the Plum Point Power Plant discussed below. The amount of capacity purchased under such contracts supplements our on-system capacity and contributes to meeting our current expectations of future power needs. To the extent we do not need such capacity to meet our customers’ needs, we can sell it in the wholesale market.
During the first quarter of 2006, we plan to enter into an agreement to add another 100 megawatts of power to our system. This power will come from the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own 50 megawatts of the project’s capacity. We will also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015.
Our forecasted customer growth indicates we will be below the SPP’s 12% minimum capacity margin requirement beginning in 2007. As a result, we have purchased, and are installing at our Riverton facility, a
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Siemens V84.3A2 combustion turbine with an expected summer capacity of 155 megawatts to be operational in 2007.
On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase all of the energy generated at the Elk River Windfarm located in Butler County, Kansas. Construction of the windfarm began in May 2005, we began receiving test energy in October 2005 and the project was declared commercial on December 15, 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 have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or 10% of our annual needs. We anticipate the cost of this contract to be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation. Savings in the fourth quarter of 2005 alone totaled approximately $3.3 million over what we would have paid to purchase the energy at average prices on the open market.
On February 4, 2005, we filed an application with the Missouri Public Service Commission (MPSC) seeking approval of an Experimental Regulatory Plan (Plan) concerning our possible participation in a new 800-850 MW coal-fired unit (Iatan 2) to be operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri, or other baseload generation options. Our application also sought a certificate of convenience and necessity to participate in Iatan 2, if necessary, and in connection therewith, obtain approval that is intended to provide adequate assurance to potential investors to make financial options available to us concerning our potential investment in Iatan 2. On July 18, 2005, we filed a Stipulation and Agreement (Agreement) regarding our Plan with the MPSC for its consideration and approval conditioned upon our participation in Iatan 2. The Agreement contains conditions related to our infrastructure investments, including Iatan 2, environmental investments in Iatan 1, the 155 MW V84.3A2 combustion turbine at our Riverton plant and installing Selective Catalytic Reduction (SCR) equipment at the Asbury coal-fired plant. The other parties to the Agreement include the Missouri Department of Natural Resources, the MPSC Staff, two of our industrial customers and the Office of the Public Counsel. The MPSC issued an order on August 2, 2005 approving the Agreement with an effective date of August 12, 2005.
In relation to the above Plan, we entered into a letter of intent with KCP&L on June 10, 2005 with respect to our potential purchase of an undivided ownership interest in the proposed 800-850 MW coal-fired Iatan 2. The total estimated construction budget for Iatan 2 is approximately $1.26 billion with the first major expenditures for our share, approximately $28.7 million and $51.9 million, planned in 2007 and 2008, respectively. The letter of intent relates to an allocation of at least 100 MW of generation capacity (and a proportionate share of the construction, operation and maintenance costs) to us. The letter of intent, insofar as it relates to Iatan 2, is not binding on the parties. The letter of intent also contains a clarification as to our obligations with respect to environmental upgrades at Iatan 1 and an agreement to reallocate certain interests in common facilities at Iatan 1 to the owners of Iatan 2. Empire currently owns a 12% interest in Iatan 1.
A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts. Our share will decrease from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, Scrubber, and bag house are completed, currently estimated to be late in the fourth quarter of 2008.
The following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated contract years (which run from June 1 to May 31 of the following year). The capacity ratings we use for our generating units are based on summer rating conditions as utilized by
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SPP guidelines. The 155 megawatts from the new combustion turbine are included under anticipated owned capacity beginning in 2007. The purchased power to be received from the Elk River windfarm and the proposed Iatan 2 project are also included in this chart. Because the wind power is an intermittent, non-firm resource, we do not expect the SPP to allow us to count a substantial amount of the wind power as capacity. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
| Contract Year* | | | | Purchased
Power
Commitment | | Anticipated
Owned
Capacity | | Total | |
| 2005 | | | 162 | | | | 1102 | | | 1264 | |
| 2006 | | | 162 | | | | 1100 | | | 1262 | |
| 2007 | | | 162 | | | | 1255 | | | 1417 | |
| 2008 | | | 162 | | | | 1255 | | | 1417 | |
| 2009 | | | 162 | | | | 1257 | | | 1419 | |
**2010 | | | 50 | | | | 1407 | | | 1457 | |
* Contract years begin June 1 and run through May 31 of the following year.
** The contract year 2010 assumes 50 megwatts of purchased power capacity from Plum Point, 50 megawatts of owned capacity from Plum Point and 100 megawatts of owned capacity from Iatan 2.
The charges for capacity purchases under the Westar contract referred to above during calendar year 2005 amounted to approximately $16.2 million. Minimum charges for capacity purchases under the Westar contract total approximately $81.0 million for the period June 1, 2005 through May 31, 2010.
The maximum hourly demand on our system reached a record high of 1,087 megawatts on July 22, 2005. Our previous record peak of 1,041 megawatts was established in August 2003. A new maximum hourly winter demand of 1,031 megawatts was set on December 9, 2005. Our previous winter peak of 987 megawatts was established on January 23, 2003.
Construction Program
Total gross property additions (including construction work in progress) for the three years ended December 31, 2005, amounted to $181.1 million and retirements during the same period amounted to $22.6 million. Please refer to Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for more information.
Our total capital expenditures, including allowance for funds used during construction (AFUDC), but excluding capitalized software costs and expenditures to retire assets, were $73.9 million in 2005 and for the next three years are estimated for planning purposes to be as follows:
| | Estimated Capital Expenditures
(amounts in millions) | |
| | 2006 | | 2007 | | 2008 | | Total | |
New generating facilities | | $ | 49.3 | | $ | 62.8 | | $ | 78.7 | | $ | 190.8 | |
Additions to existing generating facilities | | 23.4 | | 39.8 | | 26.7 | | 89.9 | |
Transmission facilities | | 12.8 | | 7.2 | | 7.3 | | 27.3 | |
Distribution system additions | | 26.0 | | 34.4 | | 33.9 | | 94.3 | |
Non-regulated additions | | 2.1 | | 2.0 | | 3.2 | | 7.3 | |
General and other additions | | 4.2 | | 5.0 | | 3.5 | | 12.7 | |
Total | | $ | 117.8 | | $ | 151.2 | | $ | 153.3 | | $ | 422.3 | |
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Construction expenditures for new generating facilities and additions to our transmission and distribution systems to meet projected increases in customer demand constitute the majority of the projected capital expenditures for the three-year period listed above, including approximately $14.8 million in 2006 and $7.9 million in 2007 for the purchase and installation at our Riverton facility of the planned Siemens V84.3A2 combustion turbine. Also included in new generating facilities are $6.4 million in 2006, $28.7 million in 2007 and $51.9 million in 2008 for Iatan 2 and $20.6 million in 2006, $24.6 million in 2007 and $26.9 million in 2008 for the construction of the Plum Point Power Plant.
Iatan 2 and Plum Point are important components of a long-term, least-cost resource plan to add approximately 300 megawatts of coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area, the expiration of a major purchase power contract in 2010 and our desire to reduce our dependence on natural gas-fired generation.
Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction and the availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in equipment delivery schedules, changes in customer requirements, construction delays, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and co-generators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See “-Regulation” below and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Competition.”
Fuel
In 2005, 69.1% of our total system input, based on kilowatt-hours generated, was supplied by our steam and thermal generation units, 1.1% was supplied by our hydro generation, and we purchased the remaining 29.8%, including wind energy. Coal supplied approximately 62.2% of the total fuel requirements for our generating units in 2005 based on kilowatt-hours generated. The remainder was supplied by natural gas (36.7%), oil (0.7%), and tire-derived fuel (TDF) (0.4%), which is produced from discarded passenger car tires. We expect that the amount and percentage of electricity generated by natural gas will decrease in 2006 and in the immediate future thereafter due to the 20-year contract we entered into with PPM Energy to purchase the energy generated by the Elk River Windfarm. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual needs, and the project was declared commercial on December 15, 2005. We anticipate the cost of this contract to be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation. Savings in the fourth quarter of 2005 alone totaled approximately $3.3 million over what we would have paid to purchase the energy at average prices on the open market.
Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel and TDF being used as a supplement fuel. In 2005, Asbury burned a coal blend consisting of approximately 83.5% Western coal (Powder River Basin) and 16.5% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2005, we had sufficient coal on hand to supply anticipated requirements at Asbury for 27-40 days depending on the actual blend ratio within this range. This lower level of inventory is primarily due to railroad transportation problems delivering Western coal and supply issues at the local bituminous coal mine. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Summary — Fourth Quarter Activities”.
Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by petroleum coke, natural gas and oil. During 2005, Riverton Units 7 and 8 burned an estimated blend of approximately 87.5% Western coal (Powder River Basin) and 12.5% blend fuel (local coal and petroleum coke) on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. As of
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December 31, 2005, we had 26,750 tons of Western coal and a minimal amount of blend fuel at Riverton. Riverton Unit 7 requires a minimum of approximately 25% blend fuel per day to operate. Riverton Unit 8 can burn 100% Western coal or a mix of approximately 80% Western coal and 20% blend fuel. Based on these assumptions, we had sufficient Western coal to run 27 days on both units if sufficient blend fuel is available. To date, we have been able to receive just-in-time deliveries of petroleum coke from local suppliers upon demand. We had 38 days supply of Western coal for Unit 8 if petroleum coke was not available for unit 7. This lower inventory level is also primarily due to railroad transportation problems delivering Western coal.
Our long-term contract with Peabody Holding Company, Inc. for low sulfur Western coal (Powder River Basin) for the Asbury and Riverton Plants expired in December 2004. We signed a three-year contract with Peabody on December 15, 2004 that covers approximately 60% of our anticipated 2006 Western coal requirements and approximately 30% of our anticipated 2007 Western coal requirements. This Peabody coal is supplied from the North Antelope/Rochelle mine located in Campbell County, Wyoming. We signed a new contract with Kennecott Energy, effective December 15, 2005, which will supply approximately 30% of our anticipated 2006 Western coal requirements. The Kennecott coal comes from their Antelope mine in Wyoming. We have accepted a binding proposal with Arch Coal Sales for 30% of our anticipated 2007 Western coal requirements. Arch will supply coal from their Black Thunder mine, also in Wyoming. Our remaining Western coal requirements will be supplied with short-term contracts. All of the Western coal is shipped to the Asbury Plant by rail, a distance of approximately 800 miles. The coal was delivered in prior years under a transportation contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which expired at the end of June 2005. We signed a new, five-year contract with BNSF and The Kansas City Southern Railway Company on April 8, 2005 that became effective June 30, 2005. Although the delivered price of Western coal under the new contracts was higher than the 2004 price during the first half of 2005, the delivered price increase was mitigated beginning in the third quarter of 2005 due to a combination of our new coal supply and coal transportation contracts. The overall delivered price of coal is expected to be higher in 2006 than in 2005 due to recent market fluctuations and rail transportation issues. We own one unit train set that is leased to others on a full time basis. We currently lease one aluminum unit train on a full time basis and a second set is leased on an interim basis to help alleviate the railroad transportation problems delivering Western coal. These trains deliver Western coal to the Asbury Plant. The Western coal is transported from Asbury to Riverton via truck. We have a long-term contract expiring December 31, 2007 with Phoenix Coal Sales, Inc. for a supply of blend coal. We began receiving coal from Phoenix’s Garland mine in June 2004. Previously, the Riverton Plant blend coal was supplied under the same contract out of Phoenix’s Bunker Hill mine. In 2005, the Riverton plant burned a blend of remaining Phoenix stock pile coal and petroleum coke. Both Phoenix coal and petroleum coke are transported to Riverton and Asbury via truck.
Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by KCP&L (70%), Aquila (18%) and us (12%). KCP&L is the operator of this plant and is responsible for arranging its fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet substantially all of Iatan’s requirements for 2006 and 2007, approximately 75-80% for 2008, approximately 25% for 2009 and approximately 15% for 2010. The coal is transported by rail under a contract expiring on December 31, 2010, with the Burlington Northern and Santa Fe Railway Company.
Our Energy Center and State Line combustion turbine facilities are fueled primarily by natural gas with oil also available for use as needed. In April 2003, two 50 megawatt FT8 peaking units were placed into commercial operation at the Energy Center. During 2005, fuel consumption at the Energy Center, based on kilowatt hours generated, was 77.2% natural gas with the remaining 22.8% being oil. State Line fuel consumption during 2005 was 100% natural gas. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation on Units No. 1, 2, 3 and 4. As of December 31, 2005, we have oil inventories sufficient for approximately 3 days of full load operation for these units at the Energy
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Center and 2 days of full load operation for State Line Unit No. 1. Previously, the two peaking units at the Energy Center (Units 3 and 4) could use only oil from a day tank for fuel oil storage, which allowed both units to operate at full load for approximately one day. During 2005, the fuel in the storage tanks for Energy Center Units 1 and 2 was used and replaced with fuel suitable for use in all units at the Energy Center.
We have firm transportation agreements with Southern Star Central Pipeline, Inc. with original expiration dates of July 31, 2016, for the transportation of natural gas to the State Line Power Plant for the jointly-owned Combined Cycle Unit. This date is adjusted for periods of contract suspension by us during outages of the State Line Combined Cycle Unit (SLCC). This transportation agreement can also supply natural gas to State Line Unit No. 1, the Energy Center or the Riverton Plant, as elected by us on a secondary basis. In 2002, we signed a precedent agreement with Williams Natural Gas Company (now Southern Star Central), which provides additional transportation capability for 20 years. This contract provides firm transport to the sites listed above that previously were only served on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder contracts, interruptible transport, or delivered to the plants by others. The majority of our physical natural gas supply requirements will be met by short-term forward contracts and spot market purchases. Forward natural gas commodity prices and volumes are hedged several years into the future in accordance with our Risk Management Policy in an attempt to lessen the volatility in our fuel expense and gain predictability.
The following table sets forth a comparison of the costs, including transportation and other miscellaneous costs, per million Btu of various types of fuels used in our facilities:
| | 2005 | | 2004 | | 2003 | |
Coal — Iatan | | $ | 0.786 | | $ | 0.726 | | $ | 0.750 | |
Coal — Asbury | | 1.309 | | 1.179 | | 1.155 | |
Coal — Riverton | | 1.391 | | 1.309 | | 1.307 | |
Natural Gas | | 7.208 | | 4.451 | | 3.651 | |
Oil | | 5.893 | | 6.842 | | 5.575 | |
| | | | | | | | | | |
Our weighted cost of fuel burned per kilowatt-hour generated was 2.891 cents in 2005, 1.885 cents in 2004 and 1.686 cents in 2003.
Employees
At December 31, 2005, we had 851 full-time employees, including 170 employees of Mid-America Precision Products (MAPP), of which we own a 52% controlling interest. 331 of these employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On April 29, 2003, we and the IBEW entered into a four-year labor agreement effective retroactively to November 1, 2002. This contract expires October 31, 2006. Negotiations for a new labor agreement are anticipated to begin September 1, 2006.
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ELECTRIC OPERATING STATISTICS (1)
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
Electric Operating Revenues (000s): | | | | | | | | | | | |
Residential | | $ | 149,176 | | $ | 124,394 | | $ | 125,197 | | $ | 126,088 | | $ | 110,584 | |
Commercial | | 106,093 | | 92,407 | | 90,577 | | 91,065 | | 82,237 | |
Industrial | | 59,593 | | 51,861 | | 50,643 | | 50,155 | | 44,509 | |
Public authorities | | 8,464 | | 7,441 | | 7,210 | | 7,099 | | 6,311 | |
Wholesale on-system | | 16,582 | | 13,614 | | 12,440 | | 11,868 | | 12,911 | |
Miscellaneous | | 4,934 | | 6,168 | | 6,618 | | 6,987 | | 5,583 | |
Total system | | 344,842 | | 295,885 | | 292,685 | | 293,262 | | 262,135 | |
Wholesale off-system | | 14,139 | | 7,010 | | 10,849 | | 17,185 | | 3,898 | |
Less Provision for IEC Refunds | | — | | — | | — | | 15,875 | | 2,843 | |
Total electric operating revenues (2) | | 358,981 | | 302,895 | | 303,534 | | 294,572 | | 263,190 | |
Electricity generated and purchased (000s of kWh): | | | | | | | | | | | |
Steam | | 2,446,628 | | 2,409,002 | | 2,287,352 | | 2,143,323 | | 1,969,412 | |
Hydro | | 62,325 | | 63,036 | | 58,118 | | 45,430 | | 53,635 | |
Combustion turbine | | 1,453,297 | | 1,009,259 | | 816,343 | | 943,924 | | 790,993 | |
Total generated | | 3,962,250 | | 3,481,297 | | 3,161,813 | | 3,132,677 | | 2,814,040 | |
Purchased | | 1,684,657 | | 1,726,994 | | 2,112,879 | | 2,520,421 | | 2,092,955 | |
Total generated and purchased | | 5,646,907 | | 5,208,291 | | 5,274,692 | | 5,653,098 | | 4,906,995 | |
Interchange (net) | | (126 | ) | 100 | | 91 | | (69 | ) | (264 | ) |
Total system input | | 5,646,781 | | 5,208,391 | | 5,274,783 | | 5,653,029 | | 4,906,731 | |
Maximum hourly system demand (Kw) | | 1,087,000 | | 1,014,000 | | 1,041,000 | | 987,000 | | 1,001,000 | |
Owned capacity (end of period) (Kw) | | 1,102,000 | | 1,102,000 | | 1,102,000 | | 1,004,000 | | 1,007,000 | |
Annual load factor (%) | | 55.59 | | 55.98 | | 54.28 | | 56.88 | | 54.75 | |
Electric sales (000s of kWh): | | | | | | | | | | | |
Residential | | 1,881,441 | | 1,703,858 | | 1,728,315 | | 1,726,449 | | 1,681,085 | |
Commercial | | 1,485,034 | | 1,417,307 | | 1,386,806 | | 1,378,165 | | 1,375,620 | |
Industrial | | 1,106,700 | | 1,085,380 | | 1,058,730 | | 1,027,446 | | 1,004,899 | |
Public authorities | | 111,245 | | 106,416 | | 102,338 | | 101,188 | | 100,125 | |
Wholesale on-system | | 328,803 | | 305,711 | | 308,574 | | 323,103 | | 322,336 | |
Total system | | 4,913,223 | | 4,618,672 | | 4,584,763 | | 4,556,352 | | 4,484,065 | |
Wholesale off-system | | 353,138 | | 236,232 | | 324,622 | | 735,154 | | 105,975 | |
Total electric sales | | 5,266,361 | | 4,854,904 | | 4,909,385 | | 5,291,506 | | 4,590,040 | |
Company use (000s of kWh) | | 10,263 | | 10,087 | | 10,093 | | 9,960 | | 10,134 | |
KWh Losses (000s of kWh) | | 370,157 | | 343,400 | | 355,305 | | 351,563 | | 306,557 | |
Total system input | | 5,646,781 | | 5,208,391 | | 5,274,783 | | 5,653,029 | | 4,906,731 | |
Customers (average number of monthly bills rendered): | | | | | | | | | | | |
Residential | | 134,724 | | 132,172 | | 129,878 | | 127,681 | | 125,996 | |
Commercial | | 23,684 | | 23,256 | | 23,077 | | 22,858 | | 22,670 | |
Industrial | | 365 | | 357 | | 362 | | 349 | | 337 | |
Public authorities | | 1,837 | | 1,766 | | 1,716 | | 1,690 | | 1,645 | |
Wholesale on-system | | 4 | | 4 | | 5 | | 7 | | 7 | |
Total system | | 160,614 | | 157,555 | | 155,038 | | 152,585 | | 150,655 | |
Wholesale off-system | | 17 | | 16 | | 17 | | 16 | | 7 | |
Total | | 160,631 | | 157,571 | | 155,055 | | 152,601 | | 150,662 | |
Average annual sales per residential customer (kWh) | | 13,965 | | 12,891 | | 13,307 | | 13,522 | | 13,342 | |
Average annual revenue per residential customer | | $ | 1,107 | | $ | 941 | | $ | 964 | | $ | 936 | | $ | 870 | |
Average residential revenue per kWh | | 7.93 | ¢ | 7.30 | ¢ | 7.24 | ¢ | 6.92 | ¢ | 6.52 | ¢ |
Average commercial revenue per kWh | | 7.14 | ¢ | 6.52 | ¢ | 6.53 | ¢ | 6.21 | ¢ | 5.91 | ¢ |
Average industrial revenue per kWh | | 5.38 | ¢ | 4.78 | ¢ | 4.78 | ¢ | 4.55 | ¢ | 4.35 | ¢ |
(1) See Item 6, — “Selected Financial Data” for additional financial information regarding Empire.
(2) Before intercompany eliminations.
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Executive Officers and Other Officers of Empire
The names of our officers, their ages and years of service with Empire as of December 31, 2005, positions held and effective date of such positions are presented below. All of our officers, other than Gregory A. Knapp, Bradley P. Beecher, Ronald F. Gatz, Kelly S. Walters and Laurie A. Delano (whose biographical information is set forth below), have been employed by Empire for at least the last five years.
Name | | Age at
12/31/05 | | Positions with the Company | | With the
Company since | | Officer
since |
William L. Gipson | | 48 | | President and Chief Executive Officer (2002), Executive Vice President and Chief Operating Officer (2001), Vice President — Commercial Operations (1997) | | 1981 | | 1997 |
Bradley P. Beecher(1) | | 40 | | Vice President — Energy Supply (2001), General Manager — Energy Supply (2001) | | 2001 | | 2001 |
Ronald F. Gatz(2) | | 55 | | Vice President — Strategic Development (2002), Vice President — Nonregulated Services (2001), General Manager — Nonregulated Services (2001) | | 2001 | | 2001 |
David W. Gibson(3) | | 59 | | Vice President — Regulatory and General Services (2002), Vice President — Regulatory Services (2002), Vice President — Finance and Chief Financial Officer (2001), Director of Financial Services and Assistant Secretary (1991) | | 1979 | | 1991 |
Gregory A. Knapp(4) | | 54 | | Vice President — Finance and Chief Financial Officer (2002), General Manager — Finance (2002) | | 2002 | | 2002 |
Michael E. Palmer | | 49 | | Vice President — Commercial Operations (2001), General Manager — Commercial Operations (2001), Director of Commercial Operations (1997) | | 1986 | | 2001 |
Kelly S. Walters(5) | | 40 | | Vice President — Regulatory and General Services (2006), General Manager — Regulatory and General Services (2005), Director of Regulatory and Planning (2001) | | 2001 | | 2006 |
Janet S. Watson | | 53 | | Secretary — Treasurer (1995) | | 1994 | | 1995 |
Laurie A. Delano(6) | | 50 | | Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005), Director of Financial Services (2002) | | 2002 | | 2005 |
(1) Bradley P. Beecher was previously with Empire from 1988 to 1999 and held the positions of Director of Production Planning and Administration (1993) and Director of Strategic Planning (1995). During the period from 1999 to 2001, Mr. Beecher served as the Associate Director of Marketing and Strategic Planning for the Energy Engineering and Construction Division of Black & Veatch.
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(2) Ronald F. Gatz was previously with Hook Up, Inc., a contract truck delivery business, from 1999 to 2001 as Chief Administrative Officer, and with Mercantile Bank in Joplin from 1985 to 1999 where he held the positions of Executive Vice President, Senior Credit Officer, and Chief Financial Officer.
(3) David W. Gibson will retire from his position as Vice President — Regulatory and General Services effective April 30, 2006.
(4) Gregory A. Knapp was previously with Empire from 1978 to 2000 and held the position of Controller and Assistant Treasurer (1983). During the period from 2000 to 2002, Mr. Knapp served as Controller for the Missouri Department of Transportation.
(5) Kelly S. Walters was elected Vice President — Regulatory and General Services on February 2, 2006, effective May 1, 2006. She was previously with Empire from 1988 to 1998 and held the position of Director of Internal Auditing (1997-1998). Prior to rejoining Empire, she was Director of Financial Services of Crowder College.
(6) Laurie A. Delano was elected Assistant Secretary and Assistant Treasurer on April 28, 2005 and Controller and Principal Accounting Officer effective August 1, 2005. She was previously with Empire from 1979 to 1991 and held the position of Director of Internal Auditing (1983-1991). Immediately prior to rejoining Empire, she was with Lozier Corporation, a store fixture manufacturing company, from 1997 to 2002, where she served as Plant Controller.
Regulation
General. As a public utility, we are subject to the jurisdiction of the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission (APSC) with respect to services and facilities, rates and charges, accounting, valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. The KCC also has jurisdiction over the issuance of securities because we are a regulated utility incorporated in Kansas. Our transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also subject to the jurisdiction of the FERC, under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of such facilities and accounting matters. See discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulated Segment — Results of Operations — Competition.”
During 2005, approximately 90% of our electric operating revenues were received from retail customers. Approximately 88.8%, 5.2%, 3.1% and 2.9% of such retail revenues were derived from sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 9% of our electric operating revenues during 2005 with the remaining 1% being from miscellaneous sources.
Rates. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Electric Operating Revenues and Kilowatt-Hour Sales — Rate Matters” for information concerning recent electric rate proceedings.
Fuel Adjustment Clauses. Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs without the need for a general rate proceeding. Fuel adjustment clauses are presently applicable to our retail electric sales in Oklahoma and Kansas (effective January 1, 2006) and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis. On July 14, 2005, Missouri Governor Blunt signed Bill SB 179 which authorizes the MPSC to grant fuel adjustment clauses for utilities in the state of Missouri. The bill went into effect January 1, 2006 and the MPSC is developing
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regulations to implement the legislation. We do not currently have a fuel adjustment clause in Missouri but we filed a Missouri rate case on February 1, 2006 to request transition from the Interim Energy Charge (IEC) to Missouri’s new fuel adjustment mechanism.
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 withheld allowances.
In 2005, 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, 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 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. In 2005, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances awarded to us by the EPA. As of December 31, 2005, we had 41,000 banked SO2 allowances as compared to 48,000 at December 31, 2004. Based on current SO2 usage projections, we will need to construct a scrubber at Asbury or purchase additional SO2 allowances sometime before 2015.
On July 14, 2004, we filed an application with the MPSC seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of our SO2 emission allowances issued by the EPA. On March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances.
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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 2005, approximately 6,600 tons of TDF were burned. This is equivalent to 660,000 discarded passenger car tires.
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 TDF 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 plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was renewed in December 2005. The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 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. A draft Proposal for Information Collection was submitted to the Kansas Department of Health and Environmental in December 2005. 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 Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan is expected to be required by the renewed permit for Asbury. 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 and NOx 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, Energy Center, State Line and Iatan Plants are located, but excluding Kansas, where our Riverton Plant is located. Also in mid-December 2003, the EPA issued the proposed Clean Air Mercury Rule (CAMR) regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The final CAMR was issued March 15, 2005. It is possible that we may need to make some expenditures as early as 2007 in order to meet the compliance date of January 1, 2009 for mercury analyzers and the mercury emission compliance date of January 1, 2010. The CAIR and the CAMR are not directed to specific generation units, but instead, require the states (including Missouri and Kansas) to develop State Implementation Plans (SIP) by September 2006 in order to comply with specific NOx, SO2 and/or mercury state-wide annual budgets (although Kansas is not covered by the NOx or SO2 requirements). Until these plans are finalized, we cannot determine the required emission rates of NOx, SO2 and mercury for the Asbury or Iatan Plants in Missouri or the required mercury emission rate for the
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Riverton Plant in Kansas. Also, the SIP will likely include allowance trading programs for NOx, SO2 and/or mercury that could allow compliance without additional capital expenditures.
As part of our Experimental Regulatory Plan filed with the MPSC, we have committed to install pollution control equipment required at the Iatan Plant by 2008 which will include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a Bag House, with our share of the capital cost estimated at $29 million. Of this amount, approximately $3 million is expected to be incurred in 2006, approximately $14 million in 2007 and approximately $11 million in 2008, each of which is included in our current capital expenditures budget. We have also committed to add an SCR at Asbury which we expect to be in service before January 2009. We are currently developing a schedule to perform the tie-ins with the existing plant during our scheduled 2007 fall outage. Our current cost estimate for an SCR at Asbury is $30 million, which is also included in our current capital expenditures budget. We also expect that additional pollution control equipment will be economically justified at the Asbury Plant sometime prior to 2015 and may include a FGD and a Bag House at an estimated capital cost of $75 million. At this time, we do not anticipate the installation of additional pollution control equipment at the Riverton Plant.
A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts. Our share will decrease from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and Bag House are completed, currently estimated to be late in the fourth quarter of 2008.
Conditions Respecting Financing
Our Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the Mortgage), and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. 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 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, 2005, would permit us to issue approximately $242.3 million of new first mortgage bonds based on this test at an assumed interest rate of 6.5%. 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, 2005, we had retired bonds and net property additions which would enable the issuance of at least $461.4 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2005, we are in compliance with all restrictive covenants of the Mortgage.
Under our Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in our Restated Articles) for a specified twelve-month period is at least 1-1/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred stock to be outstanding immediately after the issuance of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock. Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.
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Our Website
We maintain a website at www.empiredistrict.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and related amendments are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our Code of Ethics for the Chief Executive Officer and Senior Financial Officers, the charters for our Audit Committee, Compensation Committee and Nominating/Corporate Governance Committee, our Procedures for Reporting Complaints on Accounting, Internal Accounting Controls and Auditing Matters and our Procedures for Communicating with Non-Management Directors can also be found on our website. All of these documents are available in print to any shareholder who requests them. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.
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ITEM 1A. RISK FACTORS
Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.
Currently, our corporate credit rating and the ratings for our securities are as follows:
| | Standard & Poor’s | | Moody’s | | Fitch |
Corporate Credit Rating | | BBB | | Baa2 | | n/r |
First Mortgage Bonds | | A- | | Baa1 | | BBB+ |
First Mortgage Bonds — Pollution Control Series | | AAA | | Aaa | | n/r |
Senior Notes | | BBB- | | Baa2 | | BBB |
Trust Preferred Securities | | BB+ | | Baa3 | | BBB- |
Commercial Paper | | A-3 | | P-2 | | F2 |
Standard & Poor’s, Moody’s and Fitch currently have a negative outlook, a stable outlook and a stable outlook, respectively, on Empire.
These ratings indicate the agencies’ assessment of our ability to pay interest, distributions and principal on these securities. The lower the rating, the higher the interest cost of the securities when they are sold. If any of our ratings were to fall below investment grade (investment grade is defined as Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s and Fitch), our ability to issue short-term debt, commercial paper or other securities or to market those securities would be impaired or made more difficult.
We cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade in our senior unsecured long-term debt rating would, under the terms of our revolving credit facility, result in an increase in our borrowing costs under that credit facility. Any downgrade below investment grade could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to market risk in our fuel procurement strategy and may incur losses from these activities.
We have established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs. Within this activity, we may incur losses from these contracts. These losses could have a material adverse effect on our results of operations.
By using physical and financial instruments, we are exposed to credit risk and market risk. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be reclassified to fuel expense.
We are subject to regulation in the jurisdictions in which we operate.
We are subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including siting and construction of facilities, customer service, our ability to recover increases in our fuel and purchased power costs and the rates that we can charge customers.
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FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other activities.
Information concerning recent filings requesting increases in rates and related matters is set forth under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Regulated Segment — Electric Operating Revenues and Kilowatt-Hour Sales — Rate Matters.”
We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Despite our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our customers. They have similar authority with respect to our recovery of increases in our fuel and purchased power costs. In the event that our costs increase and we are unable to recover increased costs through base rates, interim energy charges or fuel adjustment clauses, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our results of operations.
A combination of increases in customer demand, decreases in output from our power plants and/or the failure of performance by purchased power contract counterparties could have a material adverse effect on our results of operations.
In the event that demand for power increases significantly and rapidly (due to weather or other conditions) and either our power plants do not operate as planned or the parties with which we have contracted to purchase power are not able to, or fail to, deliver that power, we would be forced to purchase power in the spot-market. Those unforeseen costs could have a material adverse effect on our results of operations. See Item 1, “Business — Fuel,” Item 2, “Properties — Electric Facilities” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulated Segment — Results of Operations — Operating Revenue Deductions” for more information.
We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of operations.
The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) 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. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. Of the factors driving expenses, fuel and purchased power costs are our largest expense items. Increases in the price of natural gas or the cost of purchased power will result in increases in electric operating expenses. Our existing strategies for mitigating such risks include hedging against changes in natural gas prices and utilizing interim energy charges and fuel adjustment mechanisms to recover actual fuel and purchased power expenses. On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates and a request for the new Missouri fuel adjustment mechanism for fuel cost recovery. At this time, we cannot predict the outcome of this rate case filing. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulated Segment — Results of Operations — Rate Matters” for more information.
Such efforts, however, may not offset or permit us to recover all of such increased costs. Therefore, significant increases in electric operating expenses or reductions in electric operating revenues may occur and result in a material adverse effect on our business, financial condition and results of operations.
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We have recently experienced, and may continue to experience, coal delivery shortfalls which could require us to reduce the output of our coal-fired generating facilities and lead to increases in our fuel and purchased power costs.
We depend upon regular deliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for the facility which supplies us with purchased power under our contract with Westar Energy. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by railroad. In recent months, due to widespread railroad congestion problems, the railroads have been unable to achieve the delivery cycle times required to maintain our plants’ inventory levels. As a result, inventory levels at our plants have declined. We expect that the railroads’ congestion problems and resulting delivery delays will continue for an indefinite period. As a result, we have implemented coal conservation and supply replacement measures to retain adequate reserve inventories at our facilities. These measures have included, or may include in the future, reducing the output of these plants, increasing the utilization of our gas-fired generation facilities, purchasing power from other suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures may result in increases in our fuel and purchased power costs and could have a material adverse effect on our financial condition and results of operations.
We are subject to environmental laws and the incurrence of environmental liabilities which may adversely affect our business, financial condition and results of operations.
We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and our existing facilities. Although we generally recover such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material adverse effect on our business, financial condition and results of operations.
Future acquisitions, including the contemplated acquisition of the Missouri natural gas distribution operations of Aquila, Inc., are subject to integration and other risks.
On September 21, 2005 we entered into an Asset Purchase Agreement with Aquila, Inc. pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila. In addition, we anticipate that we may, from time to time, selectively acquire additional regulated and non-regulated businesses or assets that we believe would provide a strategic fit with our business. Acquisitions are accompanied by risks, such as potential exposure to unknown liabilities of acquired companies and the possible loss of key employees and customers of the acquired business. In addition, we may not obtain the expected benefits or cost savings from the Missouri natural gas acquisition or any other acquisition. Further, acquisitions are subject to risks associated with the difficulty and expense of obtaining regulatory approval for the acquisitions, obtaining the necessary financing for the acquisitions and integrating the operations and personnel of the acquired businesses or assets. If any of these risks materialize, they may result in disruptions to our business and the diversion of management time and attention, which could increase the costs of operating our existing or acquired businesses or negate the expected benefits of the acquisitions.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 2. PROPERTIES
Electric Facilities
At December 31, 2005, 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 2005 accounted for approximately 35% 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. This year, due to a blade failure in February, the Asbury 2006 spring outage was moved to the first quarter with Asbury back on line by March 3, 2006. Approximately 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, 2005, Unit No. 2 has operated approximately 2,440 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. 7 was taken out of service from October 1, 2005 to November 4, 2005 for its five-year scheduled maintenance outage. 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. We have purchased, and are installing 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 near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts. Our share will decrease from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, Scrubber, and bag house are completed, currently estimated to be late in the fourth quarter of 2008. 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. KCP&L and Aquila own 70% and 18%, respectively, of the Unit. KCP&L operates the unit for the joint owners. On February 4, 2005, we filed an application with the MPSC seeking approval of an Experimental Regulatory Plan (Plan) concerning our possible participation in a new 800-850 MW coal-fired unit (Iatan 2) to be operated by KCP&L and located at the site of the existing Iatan Generating Station or other baseload generation options.
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
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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. Westar reimburses us for a percentage of the operating costs. 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.
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. We received all of the remaining $3.1 million from our insurer as of June 30, 2005.
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, the third wheel in early 2004 and the fourth and final wheel in March 2005. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri.
At December 31, 2005, 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 6,653 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 KCP&L 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.
Non-Regulated Businesses
We also have investments in non-regulated businesses which we operate through our wholly-owned subsidiary EDE Holdings, Inc. As of December 31, 2005, we owned the following: 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 Utility Intelligence, Inc., a company that distributes automated meter reading equipment; a 100% interest in Fast Freedom, Inc., an Internet provider; and a controlling 52% 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. 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 did not have a material impact on our balance sheets or statements of income in future periods.
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Gas Facilities
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price, originally $84 million in cash, plus working capital and subject to net plant adjustments, was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila will retain certain liabilities and obligations originally to have been assumed by us. We expect the acquisition to be financed with a mix of debt and equity and to be accretive to earnings in the range of $0.04 to $0.07 per year, excluding transition costs, beginning in its first full year of operations. This transaction is subject to the approval of the MPSC and other customary closing conditions. We filed an application with the MPSC on November 8, 2005 seeking approval and anticipate closing the transaction in mid 2006 through a new wholly-owned subsidiary, The Empire District Gas Co. We received notice of early termination of the Hart-Scott-Rodino Antitrust Improvements Act waiting period in January 2006. On March 1, 2006, we, Aquila Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting they approve the proposed transaction.
ITEM 3. LEGAL PROCEEDINGS
On December 10, 2004, we entered into a contract with PPM Energy to purchase all of the energy generated at the proposed Elk River Windfarm located in Butler County, Kansas. The Elk River project was 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 were Scottish Power, PLC, PacificCorp, PPM Energy, Inc., Greenlight Energy, Inc. and Elk River Windfarm LLC. The plaintiffs sought various forms of declaratory and injunctive relief under the United States and Kansas Constitutions as well as various statutory and common law bases. Plaintiffs sought, 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. The complaint was dismissed with prejudice by the Court on February 11, 2005. A notice of appeal was filed and subsequently denied by the United States Court of Appeals Tenth Circuit on September 7, 2005.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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PART II
ITEM 5. MARKET FOR 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, 2006, there were 5,812 record holders and 27,885 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 2005 and 2004 were as follows:
| | Price of Common Stock | | Dividends Paid
Per Share | |
| | _2005 | | 2004 | | | | | |
| | _High | | Low | | High | | Low | | 2005 | | 2004 | |
First Quarter | | $ | 23.93 | | $ | 21.35 | | $ | 23.48 | | $ | 21.38 | | $ | 0.32 | | $ | 0.32 | |
Second Quarter | | 24.45 | | 21.82 | | 22.99 | | 19.48 | | 0.32 | | 0.32 | |
Third Quarter | | 25.01 | | 22.30 | | 20.87 | | 19.53 | | 0.32 | | 0.32 | |
Fourth Quarter | | 23.27 | | 19.25 | | 23.00 | | 20.25 | | 0.32 | | 0.32 | |
| | | | | | | | | | | | | | | | | | | |
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, including the amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2005, our retained earnings balance was $19.7 million (compared to $29.1 million at December 31, 2004) after paying out $33.2 million in dividends during 2005. If we were to reduce our dividend per share, partially or in whole, it could have an adverse effect on our common stock price.
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, 2005, 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 2005, 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
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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.
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ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except per share amounts)
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
Operating revenues | | $ | 386,160 | | $ | 325,540 | | $ | 325,505 | | $ | 305,903 | | $ | 265,821 | |
Operating income | | $ | 53,161 | | $ | 51,540 | | $ | 61,435 | | $ | 56,837 | | $ | 43,212 | |
Total allowance for funds used during construction | | $ | 561 | | $ | 220 | | $ | 282 | | $ | 571 | | $ | 3,611 | |
Net income | | $ | 23,768 | | $ | 21,848 | | $ | 29,450 | | $ | 25,524 | | $ | 10,403 | |
Weighted average number of common shares outstanding — basic | | 25,898 | | 25,468 | | 22,846 | | 21,434 | | 17,777 | |
Basic earnings per share | | $ | 0.92 | | $ | 0.86 | | $ | 1.29 | | $ | 1.19 | | $ | 0.59 | |
Cash dividends per share | | $ | 1.28 | | $ | 1.28 | | $ | 1.28 | | $ | 1.28 | | $ | 1.28 | |
Common dividends paid as a percentage of net income | | 139.5 | % | 149.3 | % | 99.0 | % | 109.3 | % | 217.4 | % |
Allowance for funds used during construction as a percentage of net income | | 2.4 | % | 1.0 | % | 1.0 | % | 2.2 | % | 34.7 | % |
Book value per common share (actual) outstanding at end of year | | $ | 15.08 | | $ | 14.76 | | $ | 15.17 | | $ | 14.59 | | $ | 13.64 | |
Capitalization: | | | | | | | | | | | |
Common equity | | $ | 393,411 | | $ | 379,180 | | $ | 378,825 | | $ | 329,315 | | $ | 268,308 | |
Long-term debt | | $ | 409,880 | | $ | 399,917 | | $ | 410,393 | | $ | 410,998 | | $ | 358,615 | |
Ratio of earnings to fixed charges | | 2.24x | | 2.12x | | 2.44x | | 2.25x | | 1.31x | |
Total assets* | | $ | 1,122,030 | | $ | 1,027,539 | | $ | 1,025,091 | | $ | 991,034 | | $ | 904,087 | |
Plant in service at original cost | | $ | 1,289,622 | | $ | 1,254,255 | | $ | 1,221,352 | | $ | 1,125,460 | | $ | 1,080,100 | |
Capital expenditures (inc. AFUDC) | | $ | 73,856 | | $ | 41,892 | | $ | 65,906 | | $ | 76,877 | | $ | 77,316 | |
* 2001 through 2003 have been reclassified to present cost of asset removal accruals as a regulatory liability. See Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
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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. The utility operations comprise our regulated segment. We also have an other segment which includes investments in certain non-regulated businesses including fiber optics, Internet access, close-tolerance custom manufacturing and customer information system software services. These businesses are held in our wholly-owned subsidiary, EDE Holdings, Inc. In 2005, 92.9% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water, both of which are included in our regulated segment, and 6.7% from our non-regulated businesses.
The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) 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 recovery of our costs (primarily fuel and purchased power) and/or 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. 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. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years, although our customer growth for the twelve months ended December 31, 2005 was 1.9%. 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 power, coal and natural gas for our energy supply. 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 improve predictability. Our recent Missouri rate case order also contained factors to help mitigate the above costs, including an Interim Energy Charge (IEC), designed to recover variable fuel and purchased power costs we incur which are higher than such costs included in the base rates allowed in our rate case. However, due to the extremely high fuel prices, IEC revenues recorded in the second, third and fourth quarters of 2005 did not recover all the Missouri related fuel and purchased power costs incurred in those quarters. As a result, on February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29.5 million, or 9.63%, and requested transition from the IEC to Missouri’s new fuel adjustment mechanism. Our recent Missouri rate case order also contained a change in the recognition of pension costs, allowing us to defer the Missouri portion of any costs above the amount included in our rate case as a regulatory asset. In addition, the Arkansas Public Service Commission (APSC) allowed us to adjust our annual Energy Cost Recovery (ECR) rate midway through
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the regulatory year due to higher gas prices with the adjusted interim rate effective October 1, 2005 through March 31, 2006.
During the first quarter of 2006, we plan to enter into an agreement to add another 100 megawatts of power to our system. This power will come from the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own 50 megawatts of the project’s capacity. We will also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015.
Plum Point and Iatan 2, are important components of a long-term, least-cost resource plan to add approximately 300 megawatts of coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area, the expiration of a major purchase power contract in 2010 and our desire to reduce our dependence on natural gas-fired generation.
For the twelve months ended December 31, 2005, basic and diluted earnings per weighted average share of common stock were $0.92 as compared to $0.86 for the twelve months ended December 31, 2004. As reflected in the table below, the primary negative driver for the period ended December 31, 2005 was increased fuel and purchased power costs, while the primary positive driver for the period was increased revenues.
The following reconciliation of basic earnings per share between 2004 and 2005 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current years. The reconciliation presents the after tax impact of significant items and components of the income statement on a per share basis before the impact of additional stock issuances which is presented separately. On-system electric revenues include approximately $6.7 million of the collected IEC which is not expected to be refunded and fuel reflects a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period. Earnings per share for the years ended December 31, 2004 and 2005 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.
Earnings Per Share — 2004 | | $ | 0.86 | |
Revenues | | | |
On–System — Electric | | $ | 1.30 | |
Off–System and other — Electric | | 0.15 | |
Non–Regulated | | 0.12 | |
Expenses | | | |
Fuel and purchased power | | (1.25 | ) |
Regulated–other (employee health care expense only) | | (0.02 | ) |
Regulated–other (all other) | | (0.01 | ) |
Non–Regulated | | (0.06 | ) |
Maintenance and repairs | | 0.00 | |
Depreciation and amortization | | (0.13 | ) |
Other taxes | | (0.03 | ) |
Interest charges | | 0.01 | |
Other income and deductions | | 0.00 | |
Dilutive effect of additional shares | | (0.02 | ) |
Earnings Per Share — 2005 | | $ | 0.92 | |
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Fourth Quarter Activities
Earnings for the fourth quarter of 2005 were $1.3 million, or $0.05 per share, compared to fourth quarter 2004 earnings of $2.0 million, or $0.08 per share. While an increase in total revenues for the fourth quarter of 2005 contributed an estimated $0.48 per share as compared to the fourth quarter of 2004, primarily due to rate increases, increases in total fuel and purchased power costs negatively impacted earnings per share by an estimated $0.45 per share. Increased depreciation rates also negatively impacted earnings an estimated $0.04 per share. In the fourth quarter of 2005, we recorded income of approximately $0.5 million, net of taxes, to correct for the net impact of certain errors related to income taxes and jointly-owned plant pension accounting. We believe this adjustment is immaterial to our consolidated income statement for the three-month and twelve-month periods ended December 31, 2005.
Included in the fourth quarter results is a loss from our non-regulated businesses. These businesses reported a net loss of $1.1 million in the fourth quarter of 2005 compared to a $1.8 million net loss in the fourth quarter of 2004. The loss resulted from our software services business.
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price, originally $84 million in cash, plus working capital and subject to net plant adjustments, was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila will retain certain liabilities and obligations originally to have been assumed by us. We expect the acquisition to be financed with a mix of debt and equity and to be accretive to earnings in the range of $0.04 to $0.07 per year, excluding transition costs, beginning in its first full year of operations. This transaction is subject to the approval of the Missouri Public Service Commission (MPSC) and other customary closing conditions. We filed an application with the MPSC on November 8, 2005 seeking approval and anticipate closing the transaction in mid 2006. We received notice of early termination of the Hart-Scott-Rodino Antitrust Improvements Act waiting period in January 2006. On March 1, 2006, we, Aquila Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting they approve the proposed transaction.
On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4.2 million, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in rates for our Kansas electric customers of approximately $2.15 million, or 12.67%, and the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect fuel costs in the future. In addition, the Agreement allows us to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. For additional information, see “ — Results of Operations — Regulated Segment — Electric Operating Revenues and Kilowatt-Hour Sales — Rate Matters” below.
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 to be located in Butler County, Kansas. Construction of the windfarm has been completed and the project was declared commercial on December 15, 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 have contracted to purchase approximately 550,000 megawatt-hours per year of energy, or approximately 10% of our annual needs from the project. 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. Savings in the fourth quarter of 2005 alone totaled
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approximately $3.3 million over what we would have paid to purchase the energy at average prices on the open market.
Several of the nation’s utilities are experiencing decreased coal inventory levels due to railroad transportation problems delivering Western coal. We also are experiencing a declining inventory situation. As of December 31, 2005, we had approximately 27 days of Western coal inventory at our Riverton plant and approximately 27-40 days (depending on the actual blend ratio) of Western coal inventory at our Asbury plant, compared to over 70 days and approximately 75 days, respectively, as of June 30, 2005. Due to recent railroad congestion problems affecting delivery cycle times, we will remain in a declining inventory situation until a change in circumstances occurs. During the third and fourth quarters of 2005, we leased a train on an interim basis, which slowed the rate of decline. Similar issues, such as slow cycle times, have also affected Iatan. We have implemented coal conservation measures at both Asbury and Riverton, including increased use of local coals not dependant upon railroad transportation. We have begun coal conservation measures at Iatan which had an estimated $0.75 million negative impact on our earnings in November and December of 2005. Also, power deliveries under our purchase power contract with Westar Energy were reduced for a period due to coal conservation efforts by Westar which we expect will have a $0.6 million negative impact on our earnings in the first quarter of 2006. The coal conservation measures at Iatan are expected to have a minimal impact on our 2006 first quarter earnings. This coal transportation situation and our coal conservation and supply replacement measures could have an adverse effect on our fuel and purchased power costs in future periods.
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RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the results of operations for 2005, compared to 2004, and for 2004, compared to 2003.
Regulated Segment
Electric Operating Revenues and Kilowatt-Hour Sales
Electric operating revenues comprised approximately 92.9% of our total operating revenues during 2005. Of these total electric operating revenues, approximately 41.6% were from residential customers, 29.6% from commercial customers, 16.6% from industrial customers, 4.6% from wholesale on-system customers, 3.9% from wholesale off-system transactions and 3.7% from miscellaneous sources, primarily transmission services. The breakdown of our customer classes has not significantly changed from 2004 or 2003.
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:
| | kWh Sales
(in millions) | |
| | 2005 | | 2004* | | % Change | | 2004 | | 2003* | | % Change | |
Residential | | 1,881.5 | | 1,703.9 | | | 10.4 | % | | 1,703.9 | | 1,728.3 | | | (1.4 | )% | |
Commercial | | 1,485.0 | | 1,417.3 | | | 4.8 | | | 1,417.3 | | 1,386.8 | | | 2.2 | | |
Industrial | | 1,106.7 | | 1,085.4 | | | 2.0 | | | 1,085.4 | | 1,058.7 | | | 2.5 | | |
Wholesale On-System | | 328.8 | | 305.7 | | | 7.6 | | | 305.7 | | 308.6 | | | (0.9 | ) | |
Other** | | 112.9 | | 108.0 | | | 4.5 | | | 108.0 | | 103.9 | | | 4.0 | | |
Total On-System | | 4,914.9 | | 4,620.3 | | | 6.4 | | | 4,620.3 | | 4,586.3 | | | 0.7 | | |
| | Operating Revenues
(in millions) | |
| | 2005*** | | 2004 | | % Change* | | 2004 | | 2003 | | % Change* | |
Residential | | | $ | 149.2 | | | $ | 124.4 | | | 19.9 | % | | $ | 124.4 | | $ | 125.2 | | | (0.6 | )% | |
Commercial | | | 106.1 | | | 92.4 | | | 14.8 | | | 92.4 | | 90.6 | | | 2.0 | | |
Industrial | | | 59.6 | | | 51.9 | | | 14.9 | | | 51.9 | | 50.6 | | | 2.4 | | |
Wholesale On-System | | | 16.6 | | | 13.6 | | | 21.8 | | | 13.6 | | 12.4 | | | 9.4 | | |
Other** | | | 8.5 | | | 7.5 | | | 13.7 | | | 7.5 | | 7.3 | | | 3.2 | | |
Total On-System | | | $ | 340.0 | | | $ | 289.8 | | | 17.3 | | | $ | 289.8 | | $ | 286.1 | | | 1.3 | | |
* 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.
*** Revenues include approximately $6.7 million of the Interim Energy Charge collected in 2005 that are not expected to be refunded to customers. See discussion below.
On-System Electric Transactions
KWh sales for our on-system customers increased approximately 6.4% during 2005 primarily due to continued sales growth and favorable weather conditions with a new record summer peak of 1,087 megawatts set on July 22, 2005 and a new record winter peak of 1,031 megawatts set on December 9, 2005. Revenues for our on-system customers increased approximately $50.2 million, or 17.3%. The March 2005 Missouri rate increase and May 2005 Arkansas rate increase (discussed below) contributed an estimated $24.8 million to revenues in 2005 while continued sales growth contributed an estimated $8.3 million.
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Weather and other factors contributed an estimated $10.5 million and the collected IEC which is not expected to be refunded contributed approximately $6.7 million during 2005. Our customer growth was 1.9% in 2005, 1.7% in 2004 and 1.6% in 2003. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years.
Residential and commercial kWh sales and associated revenues increased in 2005 due mainly to warmer temperatures in the second and third quarters of 2005 and colder temperatures in the fourth quarter of 2005 as compared to 2004, continued sales growth and the 2005 Missouri and Arkansas rate increases. Industrial kWh sales, which are not particularly weather sensitive, increased 2.0% while revenues increased 14.9%, reflecting the increased sales growth and the 2005 rate increases. On-system wholesale kWh sales increased reflecting the weather conditions and continued sales growth discussed above. Revenues associated with these FERC-regulated sales increased more than the kWh sales 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.
KWh sales for our on-system customers increased slightly during 2004 as compared to 2003, 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.
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, 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. 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.
Rate Matters
The following table sets forth information regarding electric and water rate increases since January 1, 2003:
Jurisdiction | | | | Date
Requested | | Annual
Increase
Granted | | Percent
Increase
Granted | | Date
Effective | |
Missouri — Water | | June 24, 2005 | | $ | 469,000 | | | 35.90 | % | | February 4, 2006 | |
Kansas — Electric | | April 29, 2005 | | 2,150,000 | | | 12.67 | % | | January 4, 2006 | |
Arkansas — Electric | | July 14, 2004 | | 595,000 | | | 7.66 | % | | May 14, 2005 | |
Missouri — Electric | | April 30, 2004 | | 25,705,500 | | | 9.96 | % | | March 27, 2005 | |
FERC — Electric | | March 17, 2003 | | 1,672,000 | | | 14.00 | % | | May 1, 2003 | |
Oklahoma — Electric | | March 4, 2003 | | 766,500 | | | 10.99 | % | | August 1, 2003 | |
| | | | | | | | | | | | | | |
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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 MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. 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 issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above the amount included in this rate case as a regulatory asset. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates now include a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment will be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts is greater than $10 million, the excess over $10 million will be refunded to the customers. The entire excess amount of IEC, not previously refunded, will be refunded at the end of three years, unless the IEC is terminated earlier. Each refund will include interest at the current prime rate at the time of the refund. The IEC revenues recorded in the second, third and fourth quarters of 2005 did not recover all the Missouri related fuel and purchased power costs incurred in those quarters. From inception of the IEC through December 31, 2005, the costs of fuel and purchased power were approximately $13.4 million higher than the total of the costs in our base rates and the IEC recorded during the period. Future recovery of fuel and purchased power costs through the IEC are dependent upon a variety of factors, including natural gas prices, costs of non-contract purchased power, weather conditions, plant availability and coal deliveries. At December 31, 2005, no provision for refund has been recorded.
On March 25, 2005, we, the OPC, the Missouri Industrial Energy Consumers and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications with the MPSC requesting the MPSC grant a rehearing with respect to the return on equity granted in the March 2005 Missouri rate case. The MPSC denied these applications on April 7, 2005. We and the OPC appealed this decision to the Cole County Circuit Court. Briefs have been filed by all parties and oral arguments were made on February 3, 2006. A decision by the Circuit Court is pending.
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%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%,
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effective May 14, 2005. In September 2005, the APSC allowed us to adjust our annual ECR rate midway through the regulatory year due to higher gas prices with the adjusted interim rate effective October 1, 2005 through March 31, 2006.
On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our last Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006.
On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.
On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29,513,713, or 9.63%. We expect the unprecedented high natural gas prices to continue to negatively impact our fuel and purchased power expenses in the near future. Given our limited ability to recover these added costs, we also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. At this time, we cannot predict the outcome of this rate case filing.
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 years ended December 31:
(in millions) | | 2005 | | 2004 | | 2003 | |
Revenues | | $ | 16.9 | | $ | 10.8 | | $ | 15.3 | |
Expenses | | 12.0 | | 6.3 | | 9.8 | |
Net * | | $ | 4.9 | | $ | 4.5 | | $ | 5.5 | |
*Differences could occur due to rounding.
Revenues less expenses during 2005 were higher as compared to 2004 primarily due to increased sales of our gas-fired generation in the third and fourth quarters of 2005 due to a shortage of available coal-fired generation on the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so due to the coal shortages, pushing demand onto the gas-fired units. The decrease in revenues less expenses in 2004 as compared to 2003 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
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wholesale market when it was not required to meet our own customers’ needs during that period. See “- Competition” below. The related expenses are included in our discussions of purchased power costs below.
Operating Revenue Deductions
During 2005, total operating expenses increased approximately $59.0 million (21.5%) compared to 2004. Total fuel costs increased approximately $48.3 million (75.0%) during 2005 but were offset slightly by a small decrease in total purchased power costs of approximately $0.1 million (0.2%), resulting in a net increase of $48.2 million for fuel and purchased power. The increase in fuel costs was primarily due to higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units in 2005 (an estimated $27.1 million) combined with increased generation by our gas fired units during 2005 as compared to 2004 (an estimated $15.9 million). Increased coal costs contributed approximately $3.3 million to the total fuel increase. Increased coal generation added approximately $0.2 million and increased fuel oil generation added $1.9 million. These increased costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Natural gas prices increased in 2005, in part, from the effects of hurricane activity in the Gulf of Mexico. The increased usage was due in part to weather, as well as changes in the wholesale market impacted by coal delivery issues in the Midwest. 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 2005 than to purchase power.
Regulated — other operating expenses increased approximately $1.2 million (2.3%) during 2005 as compared to 2004 primarily due to a $0.7 million increase in employee health care costs, an approximate $0.5 million increase in employee pension expense, a $0.6 million increase in professional services expense and a $0.7 million increase in transmission and distribution expense. These increases were partially offset by a $0.5 million decrease in stock compensation costs, a $0.5 million decrease in general administrative expense due to reduced costs associated with Sarbanes-Oxley Section 404 compliance, and a $0.3 million decrease in other power supply expenses. As discussed previously, effective with the second quarter of 2005, we began deferring a portion of our pension cost into a regulatory asset as authorized in our 2005 Missouri rate case. We have deferred approximately $1.5 million as of December 31, 2005. Our accumulated pension benefit obligation (ABO) was projected to be higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make an additional cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income. 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 “-Other Segment”.
Maintenance and repairs expense increased approximately $0.1 million (0.4%) during 2005 as compared to 2004. Although maintenance and repairs expense was up a total of $0.7 million at our coal-fired plants in 2005 and transmission and distribution maintenance expense was up $0.3 million, these increases were offset by a $1.1 million decrease in maintenance and repairs expense at the Energy Center. The decrease in maintenance and repairs expense at the Energy Center in 2005 was primarily due to the $1.0 million insurance deductible recorded to expense in the first quarter of 2004 related to maintenance on the Energy Center’s Unit No. 2 following a rotating blade failure on January 7, 2004 and to the second and third quarter maintenance costs related to repairs at the Energy Center not subject to insurance recovery.
Depreciation and amortization expense increased approximately $4.9 million (15.8%) during 2005 primarily due to higher depreciation rates that became effective on March 27, 2005. Total provision for
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income taxes increased approximately $1.0 million (8.6%) during 2005 due primarily to higher taxable income. Our effective federal and state income tax rate for 2005 was 33.4% as compared to 34.1% for 2004. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding income taxes. Other taxes increased approximately $1.3 million (7.0%) during 2005 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.
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 $6.3 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 $6.6 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.
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 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 January 1, 2004, we were not required under ERISA to fund any additional minimum ERISA amounts with respect to 2004. No minimum pension liability was required to be recorded as of December 31, 2004.
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 following a rotating blade failure on January 7, 2004 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
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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 our prior IEC in the first quarter of 2003.
Other Segment
Our other business segment is operated through our wholly-owned subsidiary EDE Holdings, Inc. It includes 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.
During 2005, total other segment operating revenue increased approximately $4.5 million (20.8%) while total other segment operating expense increased approximately $2.4 million (10.6%) as compared with 2004. The increase in revenues was mainly due to the activities of MAPP, the close-tolerance custom manufacturing business in which we own a 52% interest. The increase in expenses was due mainly to MAPP and Conversant, a software company in which we own a 100% interest. Conversant markets Customer Watch, an Internet-based customer information system software.
During 2004, total other segment operating revenue increased approximately $0.7 million (3.5%) while total other segment 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 in which we own a 100% interest. The increase in expenses was due mainly to MAPP and Conversant.
Our other segment businesses generated a $1.1 million net loss in 2005 as compared to a $1.8 million net loss in 2004 and a $1.4 million net loss in 2003.
We evaluated our other segment businesses for impairment at December 31, 2005 and believe, based on this analysis, that no impairment exists based on our forecast of future net cash flows. However, failure to achieve forecasted cash flows and execute software license agreements within our software business, could result in impairment in the future. We continually assess the earnings contribution of our other segment businesses.
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 $0.3 million and $0.2 million in 2005 and 2004, respectively.
Nonoperating Items
Total allowance for funds used during construction (AFUDC) increased $0.3 million in 2005 due to higher levels of construction as compared to 2004. AFUDC decreased $0.1 million in 2004 as compared to 2003 due to lower levels of construction in 2004. See Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
Total interest charges on long-term debt decreased $0.6 million (2.4%) in 2005 as compared to 2004 primarily reflecting the refinancing we completed in June 2005 by calling a higher interest debt issue and replacing it with a debt issue at a lower interest rate. See “ — Liquidity and Capital Resources” for further information. 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 November 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates. Commercial paper interest (included in other) increased $0.2 million during 2005 as compared to 2004, reflecting increased usage of short-term debt.
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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. 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 other comprehensive income are reclassified to fuel, or interest expense, in the periods in which the hedged transaction is actually realized or no longer qualifies for hedge accounting.
The following table sets forth the pre-tax gains/(losses) of our natural gas and interest rate contracts settled and reclassified, the pre-tax change in the fair market value (FMV) of our open contracts and the tax effect in Other Comprehensive Income (in millions) for the presented periods ended December 31:
| | 2005 | | 2004 | | 2003 | |
Natural gas contracts settled (1) | | $ | (4.4 | ) | $ | (11.5 | ) | $ | (9.4 | ) |
Interest rate contracts settled | | 1.4 | | 0.0 | | (2.4 | ) |
Total contracts settled | | $ | (3.0 | ) | $ | (11.5 | ) | $ | (11.8 | ) |
Change in FMV of open contracts for natural gas | | $ | 29.0 | | $ | 4.2 | | $ | 10.4 | |
Change in FMV of open contracts for interest rates | | (1.4 | ) | 0.0 | | 2.4 | |
Total change in FMV of contracts | | $ | 27.6 | | $ | 4.2 | | $ | 12.8 | |
Taxes — natural gas | | $ | (9.3 | ) | $ | 2.8 | | $ | (0.4 | ) |
Taxes — interest rates | | 0.0 | | 0.0 | | 0.0 | |
Total taxes | | $ | (9.3 | ) | $ | 2.8 | | $ | (0.4 | ) |
Total change in OCI — net of tax | | $ | 15.3 | | $ | (4.5 | ) | $ | 0.6 | |
(1) Reflected in fuel expense
Our average cost for our open financial natural gas hedges was $4.744/Dth at December 31, 2005, $4.795/Dth at December 31, 2004 and $3.695/Dth at December 31, 2003.
We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting our 5.8% Senior Notes due 2035 prior to their issuance on June 27, 2005. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes. The $1.2 million redemption premium paid in connection with the redemption of the $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 redeemed in June 2005, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes.
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 unsecured Senior Notes, 4.5% Series 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 Senior Notes, 7.70% Series 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 Senior Notes, 6.7% Series 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
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debt issue we had hedged. See Note 6 of “Notes to Consolidated Financial Statements” under Item 8. We had no interest rate derivative contracts in 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 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 and October 2004, we filed notices of intent with the SPP for the right to withdraw from the SPP effective October 31, 2004 and October 31, 2005, respectively. Such notices were given because of uncertainty surrounding the treatment from the states regarding RTO participation and cost
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recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind such notices, which we have done. On October 21, 2005, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2006. We are seeking authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of 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) has been completed and submitted which indicates a positive net benefit for our participation in the SPP RTO for the period 2006 through 2014. We filed a Stipulation and Agreement between ourselves, the MPSC staff, OPC, and SPP in February 2006 for authorization for the transfer of functional control of our transmission facilities to the SPP RTO and continued participation in the SPP RTO. Because the specific rules of SPP’s market design, scheduled to begin May 1, 2006, have not been finalized and our proceedings in the aforementioned states are pending, 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 Order 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 rate 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 filed responses to that order in May and June 2005 and in early January 2006. Even if the FERC does find we have market power or does not accept our proposed pricing method for transactions within our control area, it will not have a material impact on our financial position or results of operations because we currently have no market-price based wholesale customers within our control area. The outcome of FERC rulings for most utilities are still pending.
The FERC recently approved a cost allocation plan which allows for 33% of reliability and approved network resource upgrades to be allocated on a regional basis and the remaining 67% to be allocated to those entities determined to directly benefit from such upgrades. This structure allows for an equitable spreading of costs for regional transmission upgrades and should promote expansion of the transmission system in the SPP region. The impacts to us are still under evaluation. However, the SPP transmission expansion and cost allocation plan is expected to provide a benefit to our customers.
The SPP is scheduled to begin offering an Energy Imbalance Service (EIS) market beginning May 1, 2006. This market will provide the Imbalance Energy Ancillary service for all load in the SPP Regional
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tariff footprint. Energy prices will be based on market participant bids. In addition to imbalance service, the market will perform a security-constrained economic dispatch of all generation offered into the market and dispatch in the region on an economic basis.
Approximately 4.6% 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 2005. We have contracts with these customers that run through the first quarter of 2008.
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LIQUIDITY AND CAPITAL RESOURCES
Our net cash provided by operations was higher in 2005 as compared to 2004 mainly due to higher net income. Investments were also higher due to increased construction. Our primary sources of cash flow during 2005 were $75.0 million in internally generated funds and $32.7 million in proceeds from short-term borrowings. Our primary uses of cash during 2005 were $73.9 million in capital expenditures and $33.2 million in dividend payments, as well as an $11.5 million contribution to our pension plan.
Our capital expenditures are expected to continue to increase during 2006 and 2007 due to the purchase and expected installation of our Siemens V84.3A2 combustion turbine at our Riverton Plant. This unit is expected to be operational in 2007. Our future construction expenditures include approximately $14.8 million in 2006 and $7.9 million in 2007 for the purchase and installation of this turbine and also include $6.4 million in 2006, $28.7 million in 2007 and $51.9 million in 2008 for Iatan 2 and $20.6 million in 2006, $24.6 million in 2007 and $26.9 million in 2008 for the construction of the Plum Point Power Plant.
A detailed discussion on cash flow activity follows.
Cash Provided by Operating Activities
Our net cash flows provided by operating activities increased $0.5 million during 2005 as compared to 2004. This reflects, in part, a $1.9 million increase in net income, which includes a $5 million one-time gain in the third quarter of 2005 resulting from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period. Changes in adjustments to net income for non-cash items were $3.5 million more during 2005 versus 2004 primarily due to increases in depreciation and amortization and pension costs. A $5.0 million decrease due to increased working capital requirements, primarily due to a decrease in accounts receivable and accrued unbilled revenue, and an $11.5 million pension contribution in the fourth quarter of 2005, negatively impacted cash flows.
Prior to year end 2005, our accumulated pension benefit obligation (ABO) was projected to be higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make an additional cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income. See Note 8 of “Notes to Consolidated Financial Statements” under Item 8 for further discussion regarding our pension and post-retirement benefit plans.
Our net cash flows provided by operating activities increased $4.7 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 our prior 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.
Capital Requirements and Investing Activities
Our net cash flows used in investing activities increased $32.0 million during 2005 as compared to 2004, primarily reflecting additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at our Riverton Plant.
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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 capital expenditures totaled approximately $73.9 million, $41.9 million, and $65.9 million in 2005, 2004 and 2003, 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 2005, 2004 and 2003 is as follows:
| | Capital Expenditures | |
(in millions) | | 2005 | | 2004 | | 2003 | |
Distribution and transmission system additions | | $ | 36.2 | | $ | 26.6 | | $ | 27.7 | |
FT8 peaking units — Energy Center | | — | | — | | 20.8 | |
Combustion turbine — Riverton | | 21.7 | | 2.3 | | — | |
May 2003 tornado damage | | — | | 0.7 | | 6.7 | |
Other storms | | 0.1 | | 0.6 | | — | |
Additions and replacements — Asbury | | 4.6 | | 1.8 | | 1.0 | |
Additions and replacements — Riverton, Iatan and Ozark Beach | | 2.1 | | 1.3 | | 1.2 | |
Additions and replacements — Energy Center | | 0.2 | | 1.2 | | — | |
Additions and replacements — State Line Combined Cycle Unit | | 0.4 | | 0.4 | | — | |
Additions and replacements — State Line Unit 1 | | 2.0 | | 0.6 | | — | |
System mapping project | | 0.1 | | 1.7 | | 2.2 | |
Fiber optics (non-regulated) | | 2.0 | | 1.5 | | 2.1 | |
Other non-regulated capital expenditures | | 0.4 | | 0.8 | | 2.1 | |
Transportation | | 0.9 | | 1.0 | | 0.2 | |
Computer services projects | | — | | 0.1 | | 0.3 | |
Other | | 3.2 | | 1.4 | | 0.5 | |
Retirements and salvage (net) | | — | | (0.1 | ) | 1.1 | |
Total | | $ | 73.9 | | $ | 41.9 | | $ | 65.9 | |
Approximately 56%, 99% and 58% of the cash requirements for capital expenditures for 2005, 2004 and 2003, respectively, were satisfied with internally generated funds (funds 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 debt securities discussed below.
We estimate that our capital expenditures will total approximately $117.8 million in 2006, $151.2 million in 2007 and $153.3 million in 2008. Of these budgeted amounts, we anticipate that we will spend approximately $26.0 million, $34.4 million and $33.9 million in 2006, 2007 and 2008, respectively, for additions to our distribution system to meet projected increases in customer demand. These capital expenditure estimates also include approximately $14.8 million in 2006 and $7.9 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, $6.4 million in 2006, $28.7 million in 2007 and $51.9 million in 2008 for Iatan 2 and $20.6 million in 2006, $24.6 million in 2007 and $26.9 million in 2008 for the construction of the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. Initially we will own 50 megawatts of the project’s capacity. We will also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. Construction is scheduled to begin in the spring of 2006 and to be completed in 2010. See Note 11 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding commitments.
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Iatan 2 and Plum Point are important components of a long-term, least-cost resource plan to add approximately 300 megawatts of coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area, the expiration of a major purchase power contract in 2010 and our desire to reduce our dependence on natural gas-fired generation.
As part of our Experimental Regulatory Plan filed with the MPSC, we have committed to install pollution control equipment required at the Iatan Plant by 2008 and have also committed to add an SCR at Asbury which we expect to be in service before January 2009. For additional information, see Item 1. Business “ — Environmental Matters.”
We estimate that internally generated funds will provide approximately 19% of the funds required in 2006 for our budgeted capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/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 additional amounts needed beyond those provided by operating activities for such capital expenditures as well as the acquisition of the gas properties. 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 provided in financing activities increased $35.4 million to a provision of $2.2 million during 2005 as compared to a use of $33.1 million in 2004, primarily due to increased borrowing of short-term debt (commercial paper).
Our net cash flows used in financing activities increased $27.9 million to $33.1 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.
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 $100.0 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, 9¾% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7¼% 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.
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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, the underwriters purchased an additional 300,000 shares for approximately $6.1 million to cover over-allotments. The proceeds were added to our general funds.
On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.
We have an effective shelf registration statement with the SEC under which $400 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds (subject to receipt of state regulatory approval) are available for issuance. We plan to use a portion of the proceeds from issuances under this new shelf to fund our proposed acquisition of the Missouri natural gas distribution operations from Aquila, Inc.
On July 15, 2005, we entered into a $150 million five year unsecured credit agreement with UMB Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and the other lenders party thereto. This agreement replaced our pre-existing $100 million unsecured credit agreement, which was terminated upon entering into the new agreement. We intend to increase the facility to $226 million, with the additional $76 million to be allocated to support a letter of credit issued in connection with our participation in the Plum Point project. This extra $76 million availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point. The credit agreement also provides for $150 million of revolving loans to be available for working capital, general corporate purposes and to back-up our use of commercial paper. Interest on borrowings under the credit agreement accrues at a rate equal to, at our option, (i) the bank’s prime commercial rate plus a margin or (ii) LIBOR plus a margin, in each case based on our then current credit ratings. This agreement 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 and amortization) 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. We are in compliance with these ratios as of
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December 31, 2005. This credit agreement is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. There were no outstanding borrowings under this agreement at December 31, 2005, however, $31.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.
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, 2005 would permit us to issue approximately $242.3 million of new first mortgage bonds based on this test with an assumed interest rate of 6.5%.
As of December 31, 2005, our corporate credit rating and the ratings for our securities were as follows:
| | Standard & Poor’s | | Moody’s | | Fitch | |
Corporate Credit Rating | | | BBB | | | | Baa2 | | | n/r | |
First Mortgage Bonds | | | A- | | | | Baa1 | | | BBB+ | |
First Mortgage Bonds — Pollution Control Series | | | AAA | | | | Aaa | | | n/r | |
Senior Notes | | | BBB- | | | | Baa2 | | | BBB | |
Trust Preferred Securities | | | BB+ | | | | Baa3 | | | BBB- | |
Commercial Paper | | | A-3 | | | | P-2 | | | F2 | |
On September 22, 2005, Standard & Poor’s (S&P), reflecting our announcement of our proposed acquisition of Aquila, Inc.’s Missouri natural gas properties, placed our corporate credit rating on credit watch with negative implications. S&P stated that the acquisition comes in addition to our embarking on a capital spending program that is significantly higher than historical levels and will be partially debt financed. In addition, S&P stated that the pressure of currently high commodity prices on our cash flow relative to the level in rate recovery could cause a weakening of credit protection measures during a period when our debt levels are increasing as an additional factor in their decision. On February 13, 2006, S&P removed our corporate credit rating from credit watch, but placed us on negative outlook. S&P also reduced the rating on our commercial paper from A-2 to A-3 on February 21, 2006. Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable. 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 (investment grade is 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.
In late September we entered into an agreement with Fitch Ratings to initiate coverage of us and to assign ratings to our outstanding debt securities. On December 19, 2005, Fitch Ratings initiated coverage and assigned ratings (see table above) with a stable rating outlook. Fitch announced that their ratings reflect our low business risk position as a regulated electric utility, a stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues.
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CONTRACTUAL OBLIGATIONS
Set forth below is information summarizing our contractual obligations (not including pension obligations) as of December 31, 2005:
| | Payments Due by Period
(in millions) | |
Contractual Obligations (1) | | | | Total | | Less than
1 Year | | 1-3 Years | | 3-5 Years | | More than
5 Years | |
Long-term debt (w/o discount) | | $ | 358.1 | | | $ | — | | | | $ | - | | | | $ | 70.0 | | | | $ | 288.1 | | |
Note payable to securitization trust | | 50.0 | | | — | | | | — | | | | — | | | | 50.0 | | |
Interest on long-term debt | | 425.1 | | | 26.0 | | | | 52.4 | | | | 47.3 | | | | 299.4 | | |
Commercial paper | | 31.0 | | | 31.0 | | | | — | | | | — | | | | — | | |
Capital lease obligations | | 1.4 | | | 0.3 | | | | 0.6 | | | | 0.5 | | | | — | | |
Operating lease obligations (2) | | 305.9 | | | 13.4 | | | | 27.8 | | | | 27.9 | | | | 236.8 | | |
Purchase obligations (3) | | 314.8 | | | 77.8 | | | | 98.9 | | | | 67.8 | | | | 70.3 | | |
Open purchase orders | | 28.1 | | | 12.7 | | | | 14.5 | | | | 0.9 | | | | — | | |
Other long-term liabilities (4) | | 2.6 | | | 0.5 | | | | 2.1 | | | | — | | | | — | | |
Total Contractual Obligations | | $ | 1,517.0 | | | $ | 161.7 | | | | $ | 196.3 | | | | $ | 214.4 | | | | $ | 944.6 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.
(2) Includes monthly prepayments for wind energy from the Elk River Wind Farm which will be adjusted for actual wind purchases.
(3) Includes fuel and purchased power contracts.
(4) Other Long-term Liabilities primarily represents 100% of the long-term debt issued by Mid-America Precision Products, LLC. As of December 31, 2005, EDE Holdings, Inc. was the 52% guarantor of a $2.4 million note included in this total amount.
DIVIDENDS
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, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of December 31, 2005, our retained earnings balance was $19.7 million, compared to $29.1 million as of December 31, 2004, after paying out $33.2 million in dividends during 2005. If we were to reduce our dividend per share, partially or in whole, it could have an adverse effect on our common stock price.
Our diluted earnings per share were $0.92 for the twelve months ended December 31, 2005 and were $0.86 and $1.29 for the years ended December 31, 2004 and 2003, respectively. Dividends paid per share were $1.28 for the twelve months ended December 31, 2005 and for each of the years ended December 31, 2004 and 2003.
In addition, the Mortgage and our 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
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corporation succeeds to our rights and liabilities by a merger or consolidation. As of December 31, 2005, our level of earned surplus 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.
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 that 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 ten years effective January 1, 2005. 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 electric 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 (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. The MPSC ruled this change in the recognition of pension costs would allow us to defer the Missouri portion of any costs above the amount included in this latest rate case as a regulatory asset. Therefore, the deferral of these costs began in the second quarter of 2005. In our most recently approved Kansas Rate Case (effective January 1, 2006), the KCC also ruled that we would be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in our rate case as a regulatory asset. We now expect future pension expense or benefits will be fully recovered or recognized in rates charged to our Missouri and Kansas customers, thus lowering our sensitivity to risks and uncertainties.
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
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assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. 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.
The Financial Accounting Standards Board (FASB) announced in November 2005 they would undertake a project to change the accounting rules for pensions and other postretirement benefits (OPEB), with the new proposed rules expected to be announced in March 2006. Phase One of the project, which is expected to affect most companies’ year-end 2006 financial reporting, would add the net pension fund status and OPEB to the balance sheet. Phase Two, which is expected to take up to three years to complete, would change the methodology of pension accounting with a move toward mark-to-market accounting for retirement plans, with a requirement that a comprehensive income statement more rapidly report the effects of changes in the fair value of plan assets and liabilities from year to year. We cannot currently predict what effect the FASB’s proposals will have on our financial condition and results of operation.
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.
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As of March 3, 2006, approximately 86% of our anticipated volume of natural gas usage for the remainder of the year 2006 is hedged (either through financial derivative contracts or physical forward purchase agreements which include any physical gas in storage) at an average price of $5.965 per Dekatherm (Dth). In addition, the following percentages and amounts of our anticipated volume of natural gas usage for the next seven years (representing our financial and physical hedges) are hedged at the following average prices per Dth:
Year | | | | % Hedged | | Dth Hedged | | Average Price | |
2007 | | | 55 | % | | | 5,300,000 | | | | $ | 5.700 | | |
2008 | | | 36 | % | | | 3,800,000 | | | | $ | 6.184 | | |
2009 | | | 33 | % | | | 3,696,000 | | | | $ | 5.422 | | |
2010 | | | 42 | % | | | 3,696,000 | | | | $ | 5.422 | | |
2011 | | | 42 | % | | | 3,696,000 | | | | $ | 5.422 | | |
2012 – 2013 | | | 14 | % | | | 2,400,000 | | | | $ | 7.295 | | |
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, 2005, we have recorded $55.1 million in regulatory assets and $32.9 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.
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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 2005, 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, 2005 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.
Interim Energy Charge. The March 2005 MPSC rate order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later, which allows us to recover Missouri jurisdictional variable fuel and purchased power costs we incur within a range (collar) of $21.97/Mwh (floor) and $24.11/Mwh (ceiling). The IEC is $0.002131 per kilowatt hour of customer usage. This revenue is recorded by revenue class when service is provided to the customer. If the Missouri variable fuel and purchased power cost is below the floor, we record a provision for refund of the entire IEC actual recorded dollars. If the Missouri variable fuel and purchased power cost is above the ceiling, we record all of the IEC collected as revenue. If the Missouri variable fuel and purchased power cost falls within the collar, the difference between the ceiling and the variable fuel and purchased power cost will be the provision for refund. The difference between the IEC actual recorded dollars and the provision for refund is the IEC we record as revenue. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers. At December 31, 2005, no provision for refund has been recorded.
Use of Management’s Estimates. The preparation of our consolidated financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to 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.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Recently Issued and Proposed Accounting Standards under Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
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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” under Item 8 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 and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) 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 for further information.
If market interest rates average 1% more in 2006 than in 2005, our interest expense would increase, and income before taxes would decrease by less than $350,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2005. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.
Commodity Price Risk. We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives for gas.
We satisfied 62.2% of our 2005 generation fuel supply need through coal. Approximately 88% of our 2005 coal supply was Western coal. We have contracts and have accepted binding proposals to supply fuel for our coal plants through 2007. These contracts and accepted proposals satisfy approximately 92% of our anticipated fuel requirements for 2006, and 63% of our 2007 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.
We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to minimize our risk from volatile natural gas prices. We enter into physical forward and financial derivative 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 expect that increases in gas prices will be partially offset by realized gains under financial derivative transactions. As of March 3, 2006, 86%, or 4.8 million Dths’s, of our anticipated volume of natural gas usage for the remainder of 2006 is hedged. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Hedging Activities” for further information.
Based on our expected natural gas purchases for 2006, if average natural gas prices should increase 10% more in 2006 than the price at December 31, 2005, our fuel expense would increase, and income before taxes would decrease by approximately $1.6 million based on our 2006 financial hedge positions.
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Credit Risk. Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. As of December 31, 2005 and 2004, we had margin deposit assets of $2.1 million and $0 respectively and margin deposit liabilities of $7.8 million and $0 respectively.
We sell electricity and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.
Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At December 31, 2005, gross credit exposure related to these transactions totaled $49 million, reflecting the unrealized gains for contracts carried at fair value.
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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 integrated audits of The Empire District Electric Company’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 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 accompanying 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 presents 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, 2005 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, 2005 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
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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 2, 2006
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
| | December 31, | |
| | 2005 | | 2004 | |
| | ($-000’s) | |
Assets | | | | | |
Plant and property, at original cost: | | | | | |
Electric | | $ | 1,253,664 | | $ | 1,221,385 | |
Water | | 9,731 | | 9,201 | |
Non-regulated | | 26,227 | | 23,669 | |
Construction work in progress | | 37,495 | | 8,654 | |
| | 1,327,117 | | 1,262,909 | |
Accumulated depreciation and amortization | | 431,084 | | 405,874 | |
| | 896,033 | | 857,035 | |
Current assets: | | | | | |
Cash and cash equivalents | | 15,974 | | 12,594 | |
Accounts receivable — trade, net of allowance of $515 and $248, respectively | | 30,622 | | 20,053 | |
Accrued unbilled revenues | | 6,502 | | 7,600 | |
Accounts receivable — other | | 19,297 | | 12,874 | |
Fuel, materials and supplies | | 33,790 | | 32,044 | |
Unrealized gain in fair value of derivative contracts | | 7,644 | | 2,867 | |
Prepaid expenses | | 2,200 | | 1,953 | |
| | 116,029 | | 89,985 | |
Noncurrent assets and deferred charges: | | | | | |
Regulatory assets | | 55,091 | | 52,127 | |
Unamortized debt issuance costs | | 5,721 | | 5,881 | |
Unrealized gain in fair value of derivative contracts | | 23,891 | | 4,143 | |
Prepaid pension asset | | 19,167 | | 13,974 | |
Other | | 6,098 | | 4,394 | |
| | 109,968 | | 80,519 | |
Total Assets | | $ | 1,122,030 | | $ | 1,027,539 | |
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
| | December 31, | |
| | 2005 | | 2004 | |
| | ($-000’s) | |
Capitalization and Liabilities | | | | | |
Common stock, $1 par value, 100,000,000 shares authorized, 26,084,019 and 25,695,972 shares issued and outstanding, respectively | | $ | 26,084 | | $ | 25,696 | |
Capital in excess of par value | | 329,605 | | 321,632 | |
Retained earnings | | 19,692 | | 29,078 | |
Accumulated other comprehensive income, net of income tax | | 18,030 | | 2,774 | |
Total common stockholders’ equity | | 393,411 | | 379,180 | |
Long-term debt: | | | | | |
Note payable to securitization trust | | 50,000 | | 50,000 | |
Obligations under capital lease | | 658 | | 123 | |
First mortgage bonds and secured debt | | 110,015 | | 140,363 | |
Unsecured debt | | 249,207 | | 209,431 | |
Total long-term debt | | 409,880 | | 399,917 | |
Total long-term debt and common stockholders’ equity | | 803,291 | | 779,097 | |
Current liabilities: | | | | | |
Accounts payable and accrued liabilities | | 59,428 | | 36,927 | |
Current maturities of long-term debt | | 503 | | 10,462 | |
Obligations under capital lease | | 170 | | 240 | |
Commercial paper | | 30,952 | | — | |
Customer deposits | | 6,269 | | 5,724 | |
Interest accrued | | 3,543 | | 2,700 | |
Unrealized loss in fair value of derivative contracts | | 2,495 | | 1,030 | |
Taxes accrued | | 1,831 | | 1,411 | |
Other current liabilities | | 2,341 | | 709 | |
| | 107,532 | | 59,203 | |
Commitments and contingencies (Note 11) | | | | | |
Noncurrent liabilities and deferred credits: | | | | | |
Regulatory liabilities | | 32,882 | | 30,225 | |
Deferred income taxes | | 148,386 | | 132,695 | |
Unamortized investment tax credits | | 4,501 | | 5,041 | |
Postretirement benefits other than pensions | | 7,495 | | 8,232 | |
Unrealized loss in fair value of derivative contracts | | 907 | | 1,506 | |
Minority interest | | 1,014 | | 705 | |
Other | | 16,022 | | 10,835 | |
| | 211,207 | | 189,239 | |
Total Capitalization and Liabilities | | $ | 1,122,030 | | $ | 1,027,539 | |
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
| | 2005 | | 2004 | | 2003 | | |
| | ($-000’s) | | |
Operating revenues: | | | | | | | | |
Electric | | $ | 358,642 | | $ | 302,591 | | $ | 303,261 | | |
Water | | 1,447 | | 1,369 | | 1,389 | | |
Non-regulated | | 26,071 | | 21,580 | | 20,855 | | |
| | 386,160 | | 325,540 | | 325,505 | | |
Operating revenue deductions: | | | | | | | | |
Fuel | | 112,755 | | 64,440 | | 52,337 | | |
Purchased power | | 52,720 | | 52,846 | | 60,209 | | |
Regulated — other | | 54,168 | | 52,962 | | 49,753 | | |
Non-regulated — other | | 25,395 | | 22,973 | | 21,160 | | |
Maintenance and repairs | | 20,874 | | 20,794 | | 19,923 | | |
Depreciation and amortization | | 35,671 | | 30,798 | | 28,689 | | |
Provision for income taxes | | 12,010 | | 11,054 | | 15,752 | | |
Other taxes | | 19,406 | | 18,133 | | 16,247 | | |
| | 332,999 | | 274,000 | | 264,070 | | |
Operating income | | 53,161 | | 51,540 | | 61,435 | | |
Other income and (deductions): | | | | | | | | |
Allowance for equity funds used during construction | | 306 | | 122 | | — | | |
Interest income | | 341 | | 205 | | 57 | | |
Benefit (provision) for other income taxes | | 110 | | (246 | ) | 250 | | |
Minority interest | | (343 | ) | 308 | | (354 | ) | |
Other — non-operating income | | 5 | | 67 | | 53 | | |
Other — non-operating expense | | (957 | ) | (969 | ) | (860 | ) | |
| | (538 | ) | (513 | ) | (854 | ) | |
Interest charges: | | | | | | | |
Long-term debt | | 24,059 | | 24,641 | | 26,045 | |
Note payable to securitization trust | | 4,250 | | 4,250 | | — | |
Trust preferred distributions by subsidiary holding solely parent debentures | | — | | — | | 4,250 | |
Allowance for borrowed funds used during construction | | (255 | ) | (98 | ) | (282 | ) |
Other | | 801 | | 386 | | 1,118 | |
| | 28,855 | | 29,179 | | 31,131 | |
Net income | | $ | 23,768 | | $ | 21,848 | | $ | 29,450 | |
Weighted average number of common shares outstanding — basic | | 25,898 | | 25,468 | | 22,846 | |
Weighted average number of common shares outstanding — diluted | | 25,941 | | 25,521 | | 22,853 | |
Earnings per weighted average share of common stock — basic | | $ | 0.92 | | $ | 0.86 | | $ | 1.29 | |
Earnings per weighted average share of common stock — diluted | | $ | 0.92 | | $ | 0.86 | | $ | 1.29 | |
Dividends per share of common stock | | $ | 1.28 | | $ | 1.28 | | $ | 1.28 | |
| | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | 2005 | | 2004 | | 2003 | |
| | ($-000’s) | |
Net income | | $ | 23,768 | | $ | 21,848 | | $ | 29,450 | |
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability | | (2,964 | ) | (11,471 | ) | (11,752 | ) |
Change in fair value of open derivative contracts for period | | 27,617 | | 4,215 | | 12,767 | |
Income taxes | | (9,397 | ) | 2,757 | | (386 | ) |
Net change in unrealized gains on derivative contracts | | 15,256 | | (4,499 | ) | 629 | |
Comprehensive income | | $ | 39,024 | | $ | 17,349 | | $ | 30,079 | |
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
| | 2005 | | 2004 | | 2003 | |
| | ($-000’s) | |
Common stock, $1 par value: | | | | | | | |
Balance, beginning of year | | $ | 25,696 | | $ | 24,976 | | $ | 22,567 | |
Stock/stock units issued through: | | | | | | | |
Public offering | | — | | 300 | | 2,000 | |
Stock purchase and reinvestment plans | | 388 | | 420 | | 409 | |
Balance, end of year | | $ | 26,084 | | $ | 25,696 | | $ | 24,976 | |
Capital in excess of par value: | | | | | | | |
Balance, beginning of year | | $ | 321,632 | | $ | 306,728 | | $ | 260,559 | |
Excess of net proceeds over par value of stock issued: | | | | | | | |
Public offering | | — | | 5,632 | | 38,371 | |
Stock purchase and reinvestment plans | | 7,973 | | 9,272 | | 7,798 | |
Balance, end of year | | $ | 329,605 | | $ | 321,632 | | $ | 306,728 | |
Retained earnings: | | | | | | | |
Balance, beginning of year | | $ | 29,078 | | $ | 39,848 | | $ | 39,545 | |
Net income | | 23,768 | | 21,848 | | 29,450 | |
| | 52,846 | | 61,696 | | 68,995 | |
Less common stock dividends declared | | 33,154 | | 32,618 | | 29,147 | |
Balance, end of year | | $ | 19,692 | | $ | 29,078 | | $ | 39,848 | |
Accumulated other comprehensive income: | | | | | | | |
Balance, beginning of year | | $ | 2,774 | | $ | 7,273 | | $ | 6,644 | |
Reclassification adjustment for gains included in net income | | (2,964 | ) | (11,471 | ) | (11,752 | ) |
Change in fair value of open derivative contracts for period | | 27,617 | | 4,215 | | 12,767 | |
Income taxes | | (9,397 | ) | 2,757 | | (386 | ) |
Balance, end of year | | $ | 18,030 | | $ | 2,774 | | $ | 7,273 | |
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | 2005 | | 2004 | | 2003 | |
| | ($-000’s) | |
Operating activities | | | | | | | |
Net income | | $ | 23,768 | | $ | 21,848 | | $ | 29,450 | |
Adjustments to reconcile net income to cash flows: | | | | | | | |
Depreciation and amortization | | 40,158 | | 35,260 | | 32,556 | |
Pension expense | | 6,412 | | 3,006 | | 3,858 | |
Deferred income taxes, net | | 7,620 | | 11,440 | | 15,392 | |
Investment tax credit, net | | (540 | ) | (540 | ) | (550 | ) |
Allowance for equity funds used during construction | | (306 | ) | (122 | ) | — | |
Issuance of common stock and stock options for incentive plans | | 1,741 | | 2,355 | | 1,300 | |
Loss on derivatives | | — | | 162 | | 1,158 | |
Cash flows impacted by changes in: | | | | | | | |
Accounts receivable and accrued unbilled revenues | | (14,899 | ) | (1,910 | ) | 4,127 | |
Fuel, materials and supplies | | 839 | | (1,739 | ) | 2,048 | |
Prepaid expenses and deferred charges | | (3,419 | ) | 11 | | (1,017 | ) |
Accounts payable and accrued liabilities | | 20,650 | | 1,974 | | (467 | ) |
Pension contribution | | (11,500 | ) | — | | — | |
Customer deposits, interest and taxes accrued | | 1,807 | | 359 | | (465 | ) |
Other liabilities and other deferred credits | | 2,669 | | 2,420 | | 1,172 | |
Accumulated provision — rate refunds | | — | | — | | (18,719 | ) |
Net cash provided by operating activities | | $ | 75,000 | | $ | 74,524 | | $ | 69,843 | |
Investing activities | | | | | | | |
Capital expenditures — regulated | | $ | (71,237 | ) | $ | (39,192 | ) | $ | (61,997 | ) |
Capital expenditures and other investments — non-regulated | | (2,619 | ) | (2,700 | ) | (3,908 | ) |
Net cash used in investing activities | | (73,856 | ) | (41,892 | ) | (65,905 | ) |
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
| | 2005 | | 2004 | | 2003 | |
| | ($-000’s) | |
Financing activities | | | | | | | |
Proceeds from interest rate derivative | | — | | — | | 5,099 | |
Payment of interest rate derivatives | | (1,386 | ) | — | | (2,683 | ) |
Proceeds from issuance of Senior Notes | | 40,000 | | — | | 160,000 | |
Proceeds from issuance of common stock | | 6,619 | | 13,270 | | 47,251 | |
Long-term debt issuance costs | | (541 | ) | — | | (1,695 | ) |
Redemption of senior notes | | — | | — | | (100,058 | ) |
Redemption of First Mortgage Bonds | | (40,000 | ) | — | | (60,326 | ) |
Premium paid on extinguished debt | | (1,163 | ) | — | | (10,819 | ) |
Discount on issuance of senior notes | | (220 | ) | — | | (810 | ) |
Dividends | | (33,154 | ) | (32,618 | ) | (29,147 | ) |
Net proceeds (repayments) from short-term borrowings | | 32,745 | | (13,275 | ) | (12,231 | ) |
Net (repayments) proceeds from non-regulated notes payable | | (411 | ) | (369 | ) | 303 | |
Other | | (253 | ) | (154 | ) | (153 | ) |
Net cash provided by (used in) financing activities | | 2,236 | | (33,146 | ) | (5,269 | ) |
Net increase/(decrease) in cash and cash equivalents | | 3,380 | | (514 | ) | (1,331 | ) |
Cash and cash equivalents, beginning of year | | 12,594 | | 13,108 | | 14,439 | |
Cash and cash equivalents, end of year | | $ | 15,974 | | $ | 12,594 | | $ | 13,108 | |
| | | | | | | | | | |
Interest paid was $26.4 million, $27.5 million and $30.9 million for the years ended December 31, 2005, 2004, and 2003, respectively. Income taxes paid, net of refunds received, were $9.1 million, $1.5 million, and $0 for the years ended December 31, 2005, 2004, and 2003, respectively. Net income taxes paid in 2003 of $0 were due to payments offset by a refund of federal income tax of $0.75 million. Capital lease obligations incurred during the year ended December 31, 2005 for the purchase of new equipment were $0.8 million. There were no new capital lease obligations incurred during the years ended December 31, 2004 and 2003.
The accompanying notes are an integral part of these consolidated financial statements.
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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, 2005, 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 2005 were derived as follows: residential 41.6%, commercial 29.6%, industrial 16.6%, wholesale on-system 4.6%, wholesale off-system 3.9% and other 3.7%. Our electric revenues for 2005 by jurisdiction were as follows: Missouri 88.8%, Kansas 5.2%, Arkansas 2.9%, and Oklahoma 3.1%. These percentages have not significantly changed from 2004 and 2003. 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 (EDE), and its 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”. Intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our two segments. On December 31, 2003, we deconsolidated the Empire District Electric Trust I as required by Financial Accounting Standards Board (FASB) Interpretation No. 46-R (FIN 46-R).
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, 2005, the costs of all of our regulatory assets are being recovered except, for approximately $1.4 million related to
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
unamortized premiums and related costs for debt reacquired and $1.5 million related to deferred Missouri pension costs. These costs were incurred subsequent to our 2004 rate case filings. Since cost recovery of debt related costs has historically been allowed in rate cases in all of our jurisdictions and the recovery of pension costs was allowed in our last rate case, we expect them to be approved in future rate case proceedings. In addition, $1.4 million of loss remaining from interest rate derivative transactions were incurred subsequent to our 2004 rate case filings, which we expect to be approved in future rate case proceedings in all of our jurisdictions.
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.
We are currently collecting an Interim Energy Charge (IEC) of $0.002131 per kilowatt hour of customer usage authorized by the MPSC. The IEC is designed to recover variable fuel and purchased power costs we incur subject to a ceiling and floor on the amount recoverable (including realized gains or losses associated with our natural gas hedging program) which are higher than such costs included in the base rates allowed in the most recent Missouri rate case. This revenue is recorded when service is provided to the customer and subject to refund to the extent collected amounts exceed variable fuel and purchased power costs. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers. At December 31, 2005, no provision for refund has been recorded.
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 service has been provided.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Missouri rate case, effective March 27, 2005, we began accruing cost of removal in depreciation rates for mass property (includes transmission, distribution and general plant assets) on 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, 2005, and 2004, the amount of accrued cost of removal was $21.3 million and $17.6 million, respectively. We adjust this amount to reflect our actual cost of removal expenditures.
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:
| | 2005 | | 2004 | | 2003 | |
| | (000’s) | |
Provision for depreciation | | | | | | | |
Regulated | | $ | 35,416 | | $ | 30,822 | | $ | 28,917 | |
Non-regulated | | 1,770 | | 1,497 | | 1,418 | |
Total | | $ | 37,186 | | $ | 32,318 | | $ | 30,334 | |
Annual depreciation rates | | | | | | | |
Regulated | | 2.9 | % | 2.6 | % | 2.5 | % |
Non-regulated | | 7.8 | % | 7.0 | % | 7.3 | % |
Total | | 3.0 | % | 2.6 | % | 2.5 | % |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below sets forth the average depreciation rate for each class of assets, which have been consistently applied for all periods presented:
Annual Weighted Average Depreciation Rate | | | | | |
Electric fixed assets: | | | |
Production plant | | 2.2 | % |
Transmission plant | | 2.2 | % |
Distribution plant | | 3.3 | % |
General plant | | 6.5 | % |
Water | | 2.6 | % |
Non-Regulated | | 6.5 | % |
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 7.6% for 2005, 6.9% for 2004 and 1.4% for 2003, compounded semiannually, in determining AFUDC.
Asset Impairments
We 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, 2005 and 2004 and believe that no impairments exist at those dates, including assets related to our non-regulated operations. Failure to achieve forecasted cash flows or, with respect to our software business, execute software license agreements, 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 non-hedging 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.,
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 in fuel expense.
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)
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. Under these contracts, the natural gas supplies are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions.
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 ten years (effective January 1, 2005). 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 electric 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. 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.
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 of 2004, we adopted FASB staff position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”. As of December 31, 2004, accumulated postretirement benefit obligation (APBO) and net cost recognized for other post-employment benefits (OPEB) reflects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act).
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. Our plan provides prescription drug benefits that are “actuarially equivalent” to the prescription drug benefits provided under Medicare and have been certified as such. (See Note 8 for more discussion.)
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 $6.4 million, $5.4 million and $5.1 million were recorded for each of the years ended December 31, 2005, 2004, and 2003, 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 current accrued liabilities. At December 31, 2005, and 2004, these amounts were $11.8 million and $10.0 million, respectively.
Fuel, Materials and Supplies
Fuel, materials and supplies inventories consist primarily of coal, natural gas in storage and materials and supplies, which are primarily reported at average cost.
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.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 are 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 2005, 2004, and 2003 periods were 25,898,428, 25,467,740 and 22,845,952 respectively. Additional dilutive shares for the 2005, 2004, and 2003 periods were 42,680, 53,223 and 7,153, respectively. Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company’s stock price occurs. Antidilutive shares for 2005, 2004 and 2003 were 41,115, 57,384 and 79,609, respectively.
Stock-Based Compensation
At December 31, 2005, 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.) We will adopt FAS 123R in the first quarter of 2006 using the modified prospective application approach. We do not expect this to have a material impact on our stock compensation expense.
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. Upon adoption of this statement in the first quarter of 2003, we recorded a non-recurring discounted liability and a regulatory asset of approximately $0.6 million 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. $0.4 million was capitalized as regulated plant and property.
On March 30, 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that an entity must record a liability for a “conditional”
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
asset retirement obligation if the fair value of the obligation can be reasonably estimated. It also clarifies the FASB’s views on when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Upon adoption of FIN 47 in December 2005, we identified future asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. We also have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. Upon adoption of FIN 47 in the fourth quarter of 2005, we recorded a non-recurring discounted liability and a regulatory asset of approximately $2.1 million because we expect to recover these costs of removal in electric rates either through depreciation accruals or direct expenses. An additional $0.5 million was capitalized in 2005 as regulated plant and property.
All of the liabilities associated with FAS 143 and FIN 47 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. The balances at the end of 2004 and 2005 are shown below.
| | Liability
Balance
12/31/04 | | Liabilities
Recognized
12/31/05 | | Liabilities
Settled | | Accretion | | Cash Flow
Revisions | | Liability
Balance at
12/31/05 | |
| | (000’s) | |
Asset Retirement Obligation | | $ | 690 | | | $ | 2,061 | | | | $ | 0 | | | | $ | 38 | | | | $ | 52 | | | | $ | 2,841 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Also in 2003, 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, 2005 and 2004 the accrual for cost of removal was $21.3 million, and $17.6 million respectively.
Recently Issued and Proposed Accounting Standards
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 annual period 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 will adopt FAS 123R in the first quarter of 2006 using the modified prospective application approach. We do not expect this to have a material impact on our stock compensation expense.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Property, Plant and Equipment As of December 31,
(In thousands) | | 2005 | | 2004 | |
Electric plant: | | | | | |
Production | | $ | 507,055 | | $ | 501,678 | |
Transmission | | 174,680 | | 173,233 | |
Distribution | | 507,147 | | 481,179 | |
General | | 54,274 | | 54,788 | |
Electric plant | | 1,243,156 | | 1,210,878 | |
Less accumulated depreciation and amortization | | 416,163 | | 393,661 | |
Electric plant net of depreciation and amortization | | 826,993 | | 817,217 | |
Construction work in progress | | 37,364 | | 8,567 | |
Electric plant | | 864,357 | | 825,784 | |
Electric plant and property — other(1) | | | | | |
(Net of depreciation and amortization) | | 5,159 | | 5,939 | |
Water plant | | 9,731 | | 9,201 | |
Less accumulated depreciation and amortization | | 2,736 | | 2,579 | |
Water plant net of depreciation and amortization | | 6,995 | | 6,622 | |
Construction work in progress | | 4 | | 21 | |
Net water plant | | 6,999 | | 6,643 | |
Non-regulated: | | | | | |
Fiber | | 18,683 | | 16,742 | |
Other Non-regulated property | | 7,544 | | 6,927 | |
Less accumulated depreciation and amortization | | 6,837 | | 5,065 | |
Non-regulated net of depreciation and amortization | | 19,390 | | 18,604 | |
Construction work in progress | | 128 | | 65 | |
Net non-regulated property | | 19,518 | | 18,669 | |
Net plant and property | | $ | 896,033 | | $ | 857,035 | |
(1) Primarily capitalized software of $8.8 million net of amortization.
3. Regulatory Matters
Rate Increases
The following table sets forth information regarding electric and water rate increases granted since January 1, 2003:
Jurisdiction | | | | Date
Requested | | Annual
Increase
Granted | | Percent
Increase
Granted | | Date
Effective | |
Missouri — Water | | June 24, 2005 | | $ | 469,000 | | | 35.90 | % | | February 4, 2006 | |
Kansas — Electric | | April 29, 2005 | | 2,150,000 | | | 12.67 | % | | January 4, 2006 | |
Arkansas — Electric | | July 14, 2004 | | 595,000 | | | 7.66 | % | | May 14, 2005 | |
Missouri — Electric | | April 30, 2004 | | 25,705,500 | | | 9.96 | % | | March 27, 2005 | |
FERC — Electric | | March 17, 2003 | | 1,672,000 | | | 14.00 | % | | May 1, 2003 | |
Oklahoma — Electric | | March 4, 2003 | | 766,500 | | | 10.99 | % | | August 1, 2003 | |
| | | | | | | | | | | | | | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several these issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above the amount included in this rate case as a regulatory asset. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates now include a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment will be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts is greater than $10 million, the excess over $10 million will be refunded to the customers. The entire excess amount of IEC, not previously refunded, will be refunded at the end of three years, unless the IEC is terminated earlier. Each refund will include interest at the current prime rate at the time of the refund. The IEC revenues recorded in the second, third and fourth quarters of 2005 did not recover all the Missouri related fuel and purchased power costs incurred in those quarters. From inception of the IEC through December 31, 2005, the costs of fuel and purchased power were approximately $13.4 million higher than the total of the costs in our base rates and the IEC recorded during the period. Future recovery of fuel and purchased power costs through the IEC are dependent upon a variety of factors, including natural gas prices, costs of non-contract purchased power, weather conditions, plant availability and coal deliveries. At December 31, 2005, no provision for refund has been recorded.
On March 25, 2005, we, the OPC, the Missouri Industrial Energy Consumers and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications with the MPSC requesting the MPSC grant a rehearing with respect to the return on equity granted in the March 2005 Missouri rate case. The MPSC denied these applications on April 7, 2005. We and the OPC appealed this decision to the Cole County
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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Circuit Court. Briefs have been filed by all parties and oral arguments were made on February 3, 2006. A decision by the Circuit Court is pending.
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%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005. In September 2005, the APSC allowed us to adjust our annual ECR rate midway through the regulatory year due to higher gas prices with the adjusted interim rate effective October 1, 2005 through March 31, 2006.
On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our last Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006.
On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.
On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29,513,713, or 9.63%. We expect the unprecedented high natural gas prices to continue to negatively impact our fuel and purchased power expenses in the near future. Given our limited ability to recover these added costs, we also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. At this time, we cannot predict the outcome of this rate case filing.
We will continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.
Rate Matters
In accordance with FAS No. 71, we currently have deferred approximately $1.2 million of expense related to rate cases under other non-current assets and deferred charges of which $0.9 million is directly related to the Missouri rate case that was settled in the first quarter of 2005. We amortize this amount over varying periods upon the completion of the specific case. As of December 31, 2005, $0.2 million in expense related to the current Kansas case is unamortized. Based on past history, we expect this expense to be recovered in rates.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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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 29 years.
| | December 31, | |
| | 2005 | | 2004 | |
| | (000’s) | |
Regulatory assets | | | | | |
Income taxes | | $ | 26,941 | | $ | 27,628 | |
Unamortized loss on reacquired debt | | 17,458 | | 17,322 | |
Unamortized loss on interest rate derivative | | 3,349 | | 2,258 | |
Asbury five-year maintenance | | 565 | | 1,182 | |
Other postretirement benefits | | 2,780 | | 3,177 | |
Pensions — FAS 87 | | 1,456 | | — | |
Asset retirement obligation | | 2,531 | | 560 | |
Customer programs collaborative | | 11 | | — | |
Total regulatory assets | | $ | 55,091 | | $ | 52,127 | |
Regulatory liabilities | | | | | |
Income taxes | | $ | 6,701 | | $ | 7,695 | |
Unamortized gain on interest rate derivative | | 4,731 | | 4,901 | |
Gain on disposition of emission allowances | | 167 | | — | |
Costs of removal | | 21,283 | | 17,629 | |
Total regulatory liabilities | | $ | 32,882 | | $ | 30,225 | |
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.
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
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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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.
We are a member of the SPP. In October 2003 and 2004, we filed notices of intent with the SPP for the right to withdraw from the SPP effective October 31, 2004 and October 31, 2005, respectively. Such notices were given 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 notices, which we have done. On October 21, 2005, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2006. We are seeking authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of 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) has been completed and submitted which indicates a positive net benefit for our participation in the SPP RTO for the period 2006 through 2014. Because the specific rules of SPP’s market design, scheduled to begin May 1, 2006, have not been finalized and our proceedings in the aforementioned states are pending, 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.
The SPP is scheduled to begin offering an Energy Imbalance Service (EIS) market beginning May 1, 2006. This market will provide the Imbalance Energy Ancillary service for all load in the SPP Regional tariff footprint. Energy prices will be based on market participant bids. In addition to imbalance service, the market will perform a security constrained economic dispatch of all generation offered into the market and dispatch in the region on an economic basis.
4. Common Stock
Recent Issuances
On December 17, 2003, we sold 2 million shares of our common stock in an underwritten public offering for $21.15 per share. On January 8, 2004, we sold an additional 0.3 million shares to cover the underwriters’ over-allotments. The December 2003 sale resulted in proceeds of approximately $40.3 million net of issuance costs of $2.0 million. The January 2004 sale resulted in proceeds of approximately $6.1 million net of issuance costs.
Stock-Based Awards and Programs
We have several stock based awards and programs, which are described below.
Stock compensation expense relative to all of our stock based awards and programs was approximately $1.6 million, $2.2 million, and $1.2 million, in 2005, 2004, and 2003, respectively.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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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 557,820 shares available for issuance in this plan.
| | 2005 | | 2004 | | 2003 | |
Subscriptions outstanding at December 31 | | 39,391 | | 44,901 | | 38,400 | |
Maximum subscription price | | $ 21.03 | | $ 18.00 | | $ 19.03 | |
Shares of stock issued | | 43,133 | | 37,105 | | 40,121 | |
Stock issuance price | | $ 18.00 | | $ 18.02 | | $ 17.91 | |
Stock Incentive Plans
Our 1996 Incentive Plan (the 1996 Stock Incentive Plan) provided for the grant of up to 650,000 shares of common stock through January 2006. The 1996 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:
| | 2005 | | 2004 | | 2003 | |
| | | 4,432 | | | | 6,537 | | | | 6,623 | | |
| | | | | | | | | | | | | |
The terms and conditions of any option or stock grant are determined by the Board of Directors’ Compensation Committee, within the provisions of the 1996 Stock Incentive Plan. At December 31, 2005, there were 589,620 shares available for issuance under the 1996 Stock Incentive Plan.
Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 27, 2005 and provides for grants of up to 650,000 shares of common stock through January 2016. The terms of the 2006 Incentive Plan are substantially the same as the 1996 Stock Incentive Plan. Awards made prior to 2006 were made under the 1996 Stock Incentive Plan; awards made on or after January 1, 2006 are made under the 2006 Incentive Plan.
The other components of the Stock Incentive Plans are described below.
Stock Incentive Plans — Restricted Stock Awards
During February 2002 and February 2001, awards of restricted stock were made to qualified employees under the 1996 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 2005, 2004 or 2003 nor are any expected to be granted in future periods.
| | 2005 | | 2004 | | 2003 | |
Restricted shares awarded | | — | | — | | — | |
Common stock issued upon vesting of restricted shares | | 882 | | 223 | | 138 | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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Stock Incentive Plans — 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.
| | 2005 | | 2004 | | 2003 | |
Performance-based stock awards granted | | 24,200 | | 26,200 | | 30,200 | |
Common stock awarded upon vesting of performance-based stock awards | | 8,815 | | — | | — | |
Stock Incentive Plans — 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. For the 2002 awards (the first year options and dividend equivalents were awarded), the dividend equivalents converted to restricted shares of our common stock based on the fair market value of the shares on the date converted. These restricted shares would vest on the eighth anniversary of the grant date of the dividend equivalent award or, if earlier, upon exercise of the related option in full. As all the related options were exercised in 2005, the dividend equivalent restricted shares vested and were payable upon the exercise in full of the related option.
Beginning with the 2003 dividend equivalent awards, the dividend equivalents are accumulated for the three-year period and are converted to shares of our common stock based on the fair market value of the shares on the date converted. To be in compliance with Section 409A of the Internal Revenue Code added by the American Jobs Creation Act of 2004, the dividend equivalent awards were changed to vest and be payable in fully vested shares of our common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option. This modification did not have a material impact on our financial statements.
| | 2005 | | 2004 | | 2003 | |
| | | | Weighted | | | | Weighted | | | | Weighted | |
| | | | Average | | | | Average | | | | Average | |
| | | | Exercise | | | | Exercise | | | | Exercise | |
| | Options | | Price | | Options | | Price | | Options | | Price | |
Outstanding, beginning of year | | 173,100 | | | $ | 20.45 | | | 118,900 | | | $ | 19.83 | | | 69,700 | | | $ | 20.95 | | |
Granted | | 39,100 | | | $ | 22.77 | | | 54,200 | | | $ | 21.79 | | | 49,200 | | | $ | 18.25 | | |
Exercised | | 69,700 | | | $ | 20.95 | | | — | | | — | | | — | | | — | | |
Forfeited | | — | | | — | | | — | | | — | | | — | | | — | | |
Outstanding, end of year | | 142,500 | | | 20.84 | | | 173,100 | | | $ | 20.45 | | | 118,900 | | | $ | 19.83 | | |
Exercisable, end of year | | — | | | — | | | — | | | — | | | — | | | — | | |
The range of exercise prices for the options outstanding at December 31, 2005 was $18.25 to $22.77. The weighted-average remaining contractual life of outstanding options at December 31, 2005 and 2004 was 8.1 years and 8.1 years, respectively. The fair value of the options granted, which is amortized to
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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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:
| | 2005 | | 2004 | | 2003 | |
Expected life of option | | 5 Years | | 10 Years | | 10 Years | |
Risk-free interest rate | | 4.24% | | 3.96% | | 4.07% | |
Expected volatility of Empire stock | | 15.51% | | 18.80% | | 26.40% | |
Expected dividend yield on Empire stock(1) | | 0.00% | | 0.00% | | 0.00% | |
Fair value of each option granted during year | | $ | 4.38 | | $ | 4.78 | | $ | 4.99 | |
| | | | | | | | | | |
(1) The expanded Black-Scholes includes a valuation component for the existence of dividend equivalents.
Stock Unit Plan for Directors
Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based 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 compensation in the form of common stock units. The Stock Unit Plan also provided directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible Directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.
A total of 400,000 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. 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’ benefits as the Directors provide services. At December 31, 2005, there were 70,257 shares accrued to Directors’ accounts and 362,624 shares available for issuance under this plan.
| | 2005 | | 2004 | | 2003 | |
Units granted for service | | 9,528 | | 13,798 | | 7,099 | |
Units granted for dividends | | 3,842 | | 3,511 | | 3,748 | |
Units redeemed for common stock | | 1,642 | | 18,663 | | 8,914 | |
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, 2005 there were 145,778 shares available to be issued. Compensation expense was $0.7 million, $0.7 million and $0.6 million for each of the three years ended 2005, 2004 and 2003, respectively.
| | 2005 | | 2004 | | 2003 | |
Shares contributed | | 40,313 | | 40,741 | | 41,878 | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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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, 81¤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 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2005 or 2004.
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 26.0 million and 25.6 million Rights outstanding at December 31, 2005 and 2004, 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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THE EMPIRE DISTRICT ELECTRIC COMPANY
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6. Long-Term Debt
At December 31, 2005 and 2004 the balance of long-term debt outstanding was as follows:
| | 2005 | | 2004 | |
| | (In thousands) | |
Note payable to securitization trust(1) | | $ | 50,000 | | $ | 50,000 | |
First mortgage bonds: | | | | | |
7.60% Series due 2005(2) | | — | | 10,000 | |
81¤8% Series due 2009 | | 20,000 | | 20,000 | |
61¤2% Series due 2010 | | 50,000 | | 50,000 | |
7.20% Series due 2016 | | 25,000 | | 25,000 | |
73¤4% Series due 2025(3) | | — | | 30,000 | |
5.3% Pollution Control Series due 2013(4) | | 8,000 | | 8,000 | |
5.2% Pollution Control Series due 2013(4) | | 5,200 | | 5,200 | |
| | $ | 108,200 | | $ | 148,200 | |
Senior Notes, 7.05% Series due 2022(4) | | 49,937 | | 49,942 | |
Senior Notes, 41¤2% Series due 2013(5) | | 98,000 | | 98,000 | |
Senior Notes, 6.70% Series due 2033(5) | | 62,000 | | 62,000 | |
Senior Notes, 5.80% Series due 2035(5) | | 40,000 | | — | |
Long-term debt — Mid-America Precision Products(6) | | 2,380 | | 2,733 | |
Long-term debt — Fast Freedom(6) | | 218 | | 275 | |
Obligations under capital lease | | 828 | | 362 | |
Less unamortized net discount | | (1,009 | ) | (894 | ) |
| | 410,554 | | 410,619 | |
Less current obligations of long-term debt | | (503 | ) | (10,462 | ) |
Less current obligations under capital lease | | (171 | ) | (240 | ) |
Total long-term debt | | $ | 409,880 | | $ | 399,917 | |
(1) Represented by our Junior Subordinated Debentures, 8 ½% Series due 2031. We may redeem some or all of the debentures at any time on or after March 1, 2006, at 100% of their principal amount plus accrued and unpaid interest to the redemption date.
(2) Redeemed in April 2005.
(3) Redeemed in June 2005.
(4) 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.
(5) 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.
(6) EDE Holdings is the guarantor of 52% (25% at December 31, 2004) of a $2.4 million secured long-term note payable of Mid-America Precision Products (MAPP). Fast Freedom is a wholly-owned subsidiary of EDE holdings and is the resulting company of the merger of Transaeris and Joplin.com. The February 2003 purchase of Joplin.com was partially financed through long-term notes payable to the previous owners. The 2005 current obligations of these notes are included in the current obligations of long-term debt.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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On March 1, 2001, Empire District Electric Trust I (Trust) issued 2,000,000 shares of its 8½% 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 8½% 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 from corresponding payments made by us on $50,000,000 aggregate principal amount of 8½% 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.
As discussed above, at January 1, 2006, EDE Holdings is the guarantor for 52% of a $2.4 million note issued by Mid-America Precision Products (MAPP). This is fully consolidated in our balance sheet as EDE Holdings owned 52% of MAPP at December 31, 2005. EDE Holdings also guarantees 52% of MAPP’s revolving short-term credit facility of $0.85 million, of which $0.73 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 billion. 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, 2005 would permit us to issue $242.3 million of new first mortgage bonds based on this test, with an assumed interest rate of 6.5%. 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, 2005, we had retired bonds and net property additions which would enable the issuance of at least $461.4 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 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 $100.0 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, 9¾% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7¼% 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
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.
The carrying amount of our total debt exclusive of capital leases was $410.7 million and $411.1 million at December 31, 2005 and 2004 respectively, and its fair market value was estimated to be approximately $410.2 million and $425.2 million 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 (000’s)
Long-Term Debt Payout Schedule
(Excluding Unamortized Discount) | | | | Total | | Less than
1 Year | | 1-3 Years | | 3-5 Years | | More than
5 Years | |
Note payable to securitization trust | | $ | 50,000 | | | $ | — | | | | $ | — | | | $ | — | | $ | 50,000 | |
Regulated entity debt obligations | | 358,137 | | | — | | | | — | | | 70,000 | | 288,137 | |
Capital lease obligations | | 828 | | | 170 | | | | 316 | | | 342 | | — | |
Non-regulated debt obligations | | 2,598 | | | 503 | | | | 2,084 | | | 11 | | — | |
Total long-term debt obligations | | $ | 411,563 | | | $ | 673 | | | | $ | 2,400 | | | $ | 70,353 | | $ | 338,137 | |
Less current obligations and unamortized discount | | 1,683 | | | | | | | | | | | | | |
Total long-term debt | | $ | 409,880 | | | | | | | | | | | | | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Short-term Borrowings
Short-term commercial paper outstanding and notes payable averaged $5.5 million and $1.4 million daily during 2005 and 2004, respectively, with the highest month-end balances being $31.0 million and $8.5 million, respectively. The weighted average interest rates during 2005 and 2004 were 3.53% and 1.39% in each period. The weighted average interest rates of borrowings outstanding at December 31, 2005 was 4.56%. On December 31, 2004, we had no commercial paper outstanding.
On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate plus or LIBOR plus 80 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. We intend to increase the facility to $226 million, with the additional $76 million to be allocated to support a letter of credit issued in connection with our participation in the Plum Point project. This extra $76 million availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point. 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 and amortization) 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, 2005, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million 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, 2005 and 2004. However, $31.0 million of the availability thereunder was used at December 31, 2005 to back up our outstanding commercial paper.
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 to be no contribution required under ERISA in order to maintain minimum funding levels in 2006. This could change in future years, however, based on actual investment performance, changes in interest rates, any future pension plan funding, reform legislation and finalization of actuarial assumptions. Our accumulated pension benefit obligation (ABO) was projected to be higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make a cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income. At December 31, 2005, 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
83
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
in accordance with the provisions of SFAS 87, “Employers’ Accounting for Pensions” (FAS 87). Pursuant to the 2004 Missouri rate case, effective March 27, 2005, these gains or losses will be amortized over a 10 year period commencing January 1, 2005. Also, in accordance with the rate order, we will prospectively calculate the value of plan assets using a Market Related Value method (as defined in FAS 87). The current year’s market related value will equal the prior year’s market-related value of assets adjusted by contributions, disbursements, and expected return, plus 20% of the actual return in excess of (or less than) expected return for the five prior years. 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 thousands) are as follows:
2006 | | $ | 5,600 | |
2007 | | $ | 5,900 | |
2008 | | $ | 6,100 | |
2009 | | $ | 6,500 | |
2010 | | $ | 6,800 | |
2011–2015 | | $ | 40,300 | |
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:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Benefit obligation at beginning of year | | $ | 113,711 | | $ | 97,959 | | $ | 87,475 | |
Service cost | | 3,472 | | 2,759 | | 2,519 | |
Interest cost | | 6,686 | | 6,146 | | 5,828 | |
Plan amendments | | — | | — | | 503 | |
Net actuarial loss | | 4,775 | | 12,282 | | 6,750 | |
Benefits and expenses paid | | (5,556 | ) | (5,435 | ) | (5,116 | ) |
Benefit obligation at end of year | | $ | 123,088 | | $ | 113,711 | | $ | 97,959 | |
Reconciliation of Fair Value of Plan Assets:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Fair value of plan assets at beginning of year | | $ | 95,901 | | $ | 90,312 | | $ | 78,218 | |
Actual return on plan assets — gain | | 7,431 | | 10,681 | | 17,210 | |
Employer contribution(1) | | 11,500 | | 343 | | — | |
Benefits paid | | (5,556 | ) | (5,435 | ) | (5,116 | ) |
Fair value of plan assets at end of year | | $ | 109,276 | | $ | 95,901 | | $ | 90,312 | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Reconciliation of Funded Status:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Fair value of plan assets | | $ | 109,276 | | $ | 95,901 | | $ | 90,312 | |
Projected benefit obligations | | (123,088 | ) | (113,711 | ) | (97,959 | ) |
Funded status | | (13,812 | ) | (17,810 | ) | (7,647 | ) |
Unrecognized prior service cost | | 2,126 | | 2,620 | | 3,175 | |
Unrecognized net actuarial loss | | 30,853 | | 29,165 | | 21,004 | |
Prepaid pension cost | | $ | 19,167 | | $ | 13,974 | | $ | 16,532 | |
(1) Voluntary contribution in 2005 to increase plan asset values and avoid minimum pension liability.
At December 31, 2005, our accumulated benefit obligation was $104.6 million and our plan asset value was $109.3 million.
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 2005, 2004 and 2003 was 10.7%, 6.8%, and 6.6%, respectively.
Net periodic benefit pension cost/(income), some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, for 2005, 2004 and 2003, is comprised of the following components:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Service cost — benefits earned during the period | | $ | 3,472 | | $ | 2,759 | | $ | 2,519 | |
Interest cost on projected benefit obligation | | 6,685 | | 6,146 | | 5,828 | |
Expected return on plan assets | | (7,701 | ) | (7,455 | ) | (6,423 | ) |
Amortization of: | | | | | | | |
Prior service cost | | 494 | | 556 | | 556 | |
Actuarial loss | | 3,357 | | 895 | | 1,274 | |
Net periodic pension cost | | $ | 6,307 | | $ | 2,901 | | $ | 3,754 | |
Assumptions used to determine Year End Benefit Obligation
Measurement date | | | | 12/31/2005 | | 12/31/2004 | |
Weighted average discount rate | | | 5.65 | % | | | 5.75 | % | |
Rate of increase in compensation levels | | | 4.00 | % | | | 4.25 | % | |
Assumptions used to determine Net Periodic Pension Benefit Cost
Measurement date | | | | 01/01/2005 | |
Discount rate | | | 5.75 | % | |
Expected return on plan assets | | | 8.50 | % | |
Rate of compensation increase | | | 4.25 | % | |
85
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We utilized the assistance of our plan actuaries in determining the discount rate assumption at December 31, 2005. Our actuaries have developed an interest rate yield curve to enable companies to make judgments pursuant to Emerging Issues Task Force EITF Topic No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Post Retirement Benefit Plans Other Than Pensions.” The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of our pension plan and develop a single-point discount rate matching the plan’s payout structure.
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 table below outlines the sensitivity of our pension plan to potential changes in key assumptions (in millions):
| | | | Pension | |
| | | | Net Periodic | | Projected Benefit | |
| | | | Benefit Cost | | Obligation | |
(a) | | 0.25% decrease in discount rate | | | $ | 0.6 | | | | $ | 4.3 | | |
(b) | | 0.25% increase in salary scale | | | $ | 0.3 | | | | $ | 1.2 | | |
(c) | | 0.25% decrease in expected return on assets | | | $ | 0.3 | | | | N/A | | |
Allocation of Plan Assets
| | % of Fair Value as of December 31, | |
| | 2005 | | 2004 | |
Actual: | | | | | |
Equity securities | | 64% | | 69% | |
Debt securities | | 35% | | 31% | |
Other | | 1% | | 0% | |
Total | | 100% | | 100% | |
Target Range: | | | | | |
Equity securities | | 60 – 70% | | 60 – 70% | |
Debt securities | | 30 – 40% | | 30 – 40% | |
Other | | 0% | | 0% | |
Total | | 100% | | 100% | |
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:
1. Preserve capital,
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.
86
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 | · Bonds |
·Preferred Stocks | · GICs, BICs |
·Convertible Preferred Stocks | · Cash-Equivalent Securities (e.g., U.S. T-Bills, |
·Convertible Bonds | Commercial Paper, etc.) |
·Covered Options | · 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.
Those investments prohibited by the Investment Committee without prior approval are:
·Privately Placed Securities | ·Warrants |
·Commodities Futures | ·Short Sales |
·Securities of Empire District | ·Index Options |
·Derivatives | |
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.
We apply 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 $21.7 million) 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.
87
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 post-employment 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 the plan was certified in 2005. This adoption resulted in a reduction to our FAS 106 cost of $0.7 million in 2004 and $0.9 million in 2005.
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, 2005, we expect to be required to fund approximately $4.6 million in 2006. Assets in these trusts amounted to approximately $39.1 million at December 31, 2005, $33.1 million at December 31, 2004 and $27.9 million at December 31, 2003.
Our estimated benefit payments from trust assets (in thousands) are as follows:
2006 | | $ | 2,000 | |
2007 | | $ | 2,100 | |
2008 | | $ | 2,300 | |
2009 | | $ | 2,600 | |
2010 | | $ | 2,800 | |
2011–2015 | | $ | 17,400 | |
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).
88
THE EMPIRE DISTRICT ELECTRIC COMPANY
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:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Benefit obligation at beginning of year | | $ | 60,361 | | $ | 58,285 | | $ | 53,800 | |
Service cost | | 2,070 | | 1,518 | | 1,083 | |
Interest cost | | 3,312 | | 2,991 | | 3,406 | |
Amendments(1) | | (5,266 | ) | — | | (8,534 | ) |
Actuarial (gain)/loss(3) | | (1,682 | ) | (757 | ) | 10,379 | |
Plan participants contributions | | 658 | | 519 | | 417 | |
Benefits paid | | (2,779 | ) | (2,195 | ) | (2,266 | ) |
Benefit obligation at end of year | | $ | 56,674 | | $ | 60,361 | | $ | 58,285 | |
Reconciliation of Fair Value of Plan Assets:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Fair value of plan assets at beginning of year | | $ | 33,105 | | $ | 27,901 | | $ | 21,494 | |
Employer contributions | | 5,977 | | 4,556 | | 5,355 | |
Actual return on plan assets | | 2,020 | | 2,215 | | 2,895 | |
Benefits paid | | (2,579 | ) | (2,086 | ) | (2,260 | ) |
Plan participants contributions | | 626 | | 519 | | 417 | |
Fair value of plan assets at end of year | | $ | 39,149 | | $ | 33,105 | | $ | 27,901 | |
Reconciliation of Funded Status:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Fair value of plan assets | | $ | 39,149 | | $ | 33,105 | | $ | 27,901 | |
Benefit obligations | | (56,674 | ) | (60,361 | ) | (58,285 | ) |
Funded status | | (17,525 | ) | (27,256 | ) | (30,384 | ) |
Unrecognized transition obligation(1) | | — | | 8,672 | | 9,756 | |
Unrecognized prior service cost(1) | | (4,992 | ) | (7,924 | ) | (8,533 | ) |
Unrecognized net actuarial loss | | 15,022 | | 18,276 | | 21,042 | |
Accrued postretirement benefit cost | | $ | (7,495 | ) | $ | (8,232 | ) | $ | (8,119 | ) |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Postretirement benefit cost, a portion of which has been capitalized for 2005, 2004 and 2003, is as follows:
Net Periodic Postretirement Benefit Cost:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Service cost on benefits earned during the year | | $ | 2,070 | | $ | 1,518 | | $ | 1,083 | |
Interest cost on projected benefit obligation | | 3,312 | | 2,990 | | 3,406 | |
Expected return on assets | | (2,368 | ) | (1,959 | ) | (1,612 | ) |
Amortization of unrecognized transition obligation | | 1,084 | | 1,084 | | 1,084 | |
Amortization of prior service cost | | (609 | ) | (610 | ) | — | |
Amortization of actuarial loss | | 1,920 | | 1,743 | | 1,585 | |
Recognition of substantive plan | | — | | — | | 3,292 | |
Net periodic postretirement benefit cost before regulatory asset recognition(4) | | 5,409 | | 4,766 | | 8,838 | |
Recognition of regulatory asset for previously unrecorded benefit costs(2) | | — | | — | | (3,292 | ) |
Net periodic postretirement benefit cost | | $ | 5,409 | | $ | 4,766 | | $ | 5,546 | |
(1) 2003 reflects changes in our drug plan to increase the co-pay of the participants. 2005 reflects changes in our plan regarding the Medicare Part D subsidy. This 2005 change was used to offset the transition obligation and also reduced the unrecognized prior service cost.
(2) Accrued postretirement benefit cost at December 31, 2003 increased by $3.3 million related to an adjustment to recognize incremental substantive plan (as defined in FAS 106) benefit costs identified in 2004. A corresponding regulatory asset was recorded for this amount and is being afforded rate recovery in Missouri, effective with our latest Missouri rate case, effective March 27, 2005. These costs have also been afforded rate recovery in our other jurisdictions. The recorded amount of this asset at December 31, 2005 is $2.6 million.
(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 and 2005 costs reflect the impact of the Medicare Act subsidy on the net periodic postretirement benefit cost as follows:
| | 2004 | | 2005 | |
| | (In thousands) | |
Amortization of actuarial loss | | $ | 196 | | $ | 394 | |
Service cost | | 152 | | 210 | |
Interest cost | | 315 | | 335 | |
| | $ | 663 | | $ | 939 | |
Assumptions used to determine Year End Benefit Obligation
Measurement date | | 12/31/2005 | | 12/31/2004 | |
Weighted average discount rate | | | 5.65 | % | | | 5.75 | % | |
Rate of compensation increase | | | 4.00 | % | | | 5.00 | % | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Assumptions used to determine Net Periodic Benefit Cost
Measurement date | | 01/01/2005 | | 01/01/2004 | |
Discount rate | | | 5.75 | % | | | 6.25 | % | |
Expected return on plan assets (after tax) | | | 6.80 | % | | | 6.80 | % | |
Rate of compensation increase | | | 5.00 | % | | | 5.00 | % | |
We utilized the assistance of our plan actuaries in determining the discount rate assumption at December 31, 2005. Our actuaries have developed an interest rate yield curve to enable companies to make judgments pursuant to Emerging Issues Task Force EITF Topic No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Post Retirement Benefit Plans Other Than Pensions.” The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of our pension plan and develop a single-point discount rate matching the plan’s payout structure.
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 table below outlines the sensitivity of our post retirement plans to potential changes in key assumptions (in millions):
| | | | Postretirement | |
| | | | Net Periodic | | Postretirement | |
| | | | Benefit Cost | | Benefit Obligation | |
(a) | | 0.25% decrease in discount rate | | | $ | 0.2 | | | | $ | 2.3 | | |
(b) | | 0.25% increase in salary scale | | | N/A | | | | N/A | | |
(c) | | 0.25% decrease in expected return on assets | | | $ | 0.1 | | | | N/A | | |
(d) | | 1.00% increase in annual medical trend | | | $ | 1.2 | | | | $ | 7.4 | | |
The assumed 2005 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 9.5%. Each trend rate decreases 0.5% through 2015 to an ultimate rate of 5.0% for 2015 and subsequent years.
The effect of a 1% increase in each future year’s assumed healthcare cost trend rate on the current service and interest cost components of the net periodic benefit cost is $0.9 million, increasing the cost from $5.4 million to $6.3 million. The effect on the accumulated postretirement benefit obligation is $7.7 million, increasing the obligation from $56.7 million to $64.4 million. The effect of a 1% decrease in each future year’s assumed healthcare cost trend rate for these components is ($0.7) million which would decrease the current service and interest cost from $5.4 million to $4.7 million. The effect on the accumulated benefit obligation is $(6.2) million, decreasing the obligation from $56.7 million to $50.5 million.
91
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Allocation of Plan Assets
| | % of Fair Value as of December 31, | |
| | 2005 | | 2004 | |
Actual: | | | | | |
Cash equivalent | | 4% | | 11% | |
Fixed income | | 45% | | 40% | |
Equities | | 51% | | 49% | |
Total | | 100% | | 100% | |
Target Range: | | | | | |
Cash equivalent | | 0% | | 0% | |
Fixed income | | 40 – 60% | | 40 – 60% | |
Equities | | 40 – 60% | | 40 – 60% | |
Total | | 100% | | 100% | |
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 | · Cash-Equivalent Securities with a maturity |
| of one year or less |
·Preferred Stocks | · 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 | · Margin Transactions |
·Commodities Futures | · Short Sales |
·Securities of Empire District | · Index Options |
·Derivatives | · Real Estate and Real Property |
·Instrumentalities in violation of the Prohibited Transactions Standards of ERISA | · Restricted Stock |
92
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Income Taxes
Income tax expense components for the years shown are as follows:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Current income taxes: | | | | | | | |
Federal | | $ | 4,051 | | $ | 785 | | $ | (100 | ) |
State | | 769 | | (385 | ) | 760 | |
Total | | 4,820 | | 400 | | 660 | |
Deferred income taxes: | | | | | | | |
Federal | | 6,712 | | 9,936 | | 13,194 | |
State | | 908 | | 1,504 | | 2,198 | |
Total | | 7,620 | | 11,440 | | 15,392 | |
Investment tax credit amortization | | (540 | ) | (540 | ) | (550 | ) |
Total income tax expense | | $ | 11,900 | | $ | 11,300 | | $ | 15,502 | |
Deferred Income Taxes
Deferred tax assets and liabilities are reflected on our consolidated balance sheet as follows:
| | December 31, | |
| | 2005 | | 2004 | |
| | (In thousands) | |
Current deferred tax liability | | $ | 2,341 | | $ | 709 | |
Non-current deferred tax liabilities, net | | 148,386 | | 132,695 | |
Net deferred tax liabilities | | $ | 150,727 | | $ | 133,404 | |
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows:
| | December 31, | |
| | 2005 | | 2004 | |
| | (In thousands) | |
Deferred tax assets: | | | | | |
Alternative minimum tax | | $ | — | | $ | 1,600 | |
Disallowed plant costs | | 1,097 | | 1,186 | |
Gains on hedging transactions | | 2,147 | | 1,932 | |
Capitalizations to tax basis plant | | 7,879 | | 6,900 | |
Regulated liabilities related to income taxes | | 6,701 | | 7,695 | |
Post-retirement benefits other than pensions | | 5,199 | | 4,167 | |
Other | | 954 | | 855 | |
Deferred tax assets | | $ | 3,977 | | $ | 24,335 | |
Deferred tax liabilities: | | | | | |
Accelerated depreciation and amortization | | $ | 122,554 | | $ | 116,730 | |
Regulated assets related to income taxes | | 26,940 | | 27,628 | |
Loss on reacquired debt | | 5,957 | | 6,443 | |
Accumulated other comprehensive income | | 11,098 | | 1,700 | |
Losses on hedging transactions | | 1,651 | | 963 | |
Pensions | | 6,044 | | 3,177 | |
Other | | 460 | | 1,098 | |
| | $ | 174,704 | | $ | 157,739 | |
Net deferred tax liabilities | | $ | 150,727 | | $ | 133,404 | |
Effective Income Tax Rates
The differences between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were:
| | 2005 | | 2004 | | 2003 | |
Federal statutory income tax rate | | 35.0 | % | 35.0 | % | 35.0 | % |
Increase in income tax rate resulting from: | | | | | | | |
State income tax (net of federal benefit) | | 3.1 | | 2.2 | | 4.3 | |
Investment tax credit amortization | | (1.5 | ) | (1.6 | ) | (1.2 | ) |
Effect of ratemaking on property related differences | | (1.5 | ) | (0.9 | ) | (1.3 | ) |
Other | | (1.7 | ) | (0.6 | ) | (2.3 | ) |
Effective income tax rate | | 33.4 | % | 34.1 | % | 34.5 | % |
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. A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts. Our share will decrease from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and bag house are completed, currently estimated to be late in the fourth quarter of 2008. 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, 2005 and 2004, our property, plant and equipment accounts included the cost of our ownership interest in the plant of $49.8 million and $49.2 million, respectively, and accumulated depreciation of $35.4 million and $34.5 million, respectively. Expenditures recorded for our portion of ownership were $7.1 million and $6.8 million for 2005 and 2004, 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, 2005 and 2004, our property, plant and equipment accounts include the cost of our ownership interest in the unit of $153.3 million and $153.3 million, respectively, and accumulated depreciation of $22.6 million and $18.1 million, respectively. Expenditures recorded for our portion of ownership were $73.3 million and $34.9 million for 2005 and 2004, 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, as defined by FAS 133, “Accounting for Derivative Instruments and Hedging Activities,” and transportation commitments total $34.1 million for 2006, $37.0 million for 2007 through 2008, $33.7 million for 2009 through 2010 and $70.2 million for 2011 and beyond.
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 $27.5 million for 2006, $29.5 million for 2007 through 2008, and $11.2 million for 2009 through 2010.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $71.5 million thru May 31, 2010.
During the first quarter of 2006, we plan to enter into an agreement to add another 100 megawatts of power to our system. This power will come from the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own 50 megawatts of the project’s capacity and the rights to an additional 50 megawatts of capacity under a long-term purchased power agreement. We have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015.
Leases
On December 10, 2004, we entered into a 20-year contract with PPM Energy to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or 10% of our annual needs from the project, which was declared commercial on December 15, 2005. We do not own any portion of the windfarm. Monthly prepayments for wind energy from the Elk River Windfarm are adjusted for actual wind purchases and expensed as incurred. We account for this purchased power agreement as an operating lease.
We also currently have short-term leases for two unit trains to meet coal delivery demands. In addition we have a five-year capital lease for telephone equipment.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our obligations over the next five years are as follows:
| | Capital Leases | |
| | (In thousands) | |
2006 | | | $ | 313 | | |
2007 | | | 287 | | |
2008 | | | 286 | | |
2009 | | | 287 | | |
2010 | | | 262 | | |
Thereafter | | | — | | |
Total minimum payments | | | $ | 1,435 | | |
Less amount representing maintenance | | | 475 | | |
Net minimum lease payments | | | 960 | | |
Less amount representing interest | | | 132 | | |
Present value of net minimum lease payments | | | $ | 828 | | |
| | Operating Leases | |
| | (In thousands) | |
2006 | | | $ | 13,466 | | |
2007 | | | 13,326 | | |
2008 | | | 14,451 | | |
2009 | | | 14,101 | | |
2010 | | | 13,750 | | |
Thereafter | | | 236,818 | | |
Total minimum payments | | | $ | 305,913 | | |
Expenses incurred related to operating leases were $2.5 million, $0.6 million and $0.6 million for 2005, 2004 and 2003, respectively.
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.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 withheld allowances.
In 2005, 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. In 2005, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances awarded to us by the EPA. As of December 31, 2005, we had 41,000 banked SO2 allowances as compared to 48,000 at December 31, 2004. Based on current SO2 usage projections, we will need to construct a scrubber at Asbury or purchase additional SO2 allowances sometime before 2015.
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 issued by the EPA. On March 1, 2005, the Missouri Public Service Commission approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances.
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 2005, approximately 6,600 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.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was renewed in December 2005. The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 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. A draft Proposal for Information Collection was submitted to the Kansas Department of Health and Environmental in December 2005. 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 applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan is expected to be required by the renewed permit for Asbury. 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 and NOx 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, Energy Center, State Line and Iatan Plants are located, but excluding Kansas, where our Riverton Plant is located. Also in mid-December 2003, the EPA issued the proposed Clean Air Mercury Rule (CAMR) regulations for mercury emissions by power plants under the requirements of the 1990 Amendments. The final CAMR was issued March 15, 2005. It is possible that we may need to make some expenditures as early as 2007 in order to meet the compliance date of January 1, 2009 for mercury analyzers and the mercury emission compliance date of January 1, 2010. The CAIR and the CAMR are not directed to specific generation units, but instead, require the states (including Missouri and Kansas) to develop State Implementation Plans (SIP) by September 2006 in order to comply with specific NOx, SO2 and/or mercury state-wide annual budgets (although Kansas is not covered by the NOx or SO2 requirements). Until these plans are finalized, we cannot determine the required emission rates of NOx, SO2 and mercury for the Asbury or Iatan Plants in Missouri or the required mercury emission rate for the Riverton Plant in Kansas. Also, the SIP will likely include allowance trading programs for NOx, SO2 and/or mercury that could allow compliance without additional capital expenditures.
As part of our Experimental Regulatory Plan filed with the MPSC, we have committed to install pollution control equipment required at the Iatan Plant by 2008 which will include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a Bag House, with our share of the capital cost estimated at $29 million. Of this amount, approximately $3 million is expected to be incurred in 2006, approximately $14 million in 2007 and approximately $11 million in 2008 each of which is included in our current capital expenditures budget. We have also committed to add an SCR at Asbury which we expect to be in service before January 2009. We are currently developing a schedule to perform the tie-ins with the existing plant during our scheduled 2007 fall outage. Our current cost estimate for an SCR at Asbury is $30 million which is also included in our current capital expenditures budget. We also
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
expect that additional pollution control equipment will be economically justified at the Asbury Plant sometime prior to 2015 and may include a FGD and a Bag House at an estimated capital cost of $75 million. At this time, we do not anticipate the installation of additional pollution control equipment at the Riverton Plant.
A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts. Our share will decrease from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and Bag House are completed, currently estimated to be late in the fourth quarter of 2008.
12. Segment Information
The Company’s business is composed of two segments, regulated and other. The regulated segment consists of the Company’s electric and water utility businesses. The other segment consists of all our other businesses. These businesses are unregulated and include 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 Utility Intelligence, Inc., a company that distributes automated meter reading equipment; a 100% interest in Fast Freedom, Inc., an Internet provider; and a controlling 52% 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. 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.
The accounting policies for segment data are the same as for Note 1. Labor costs from regulated employees who perform duties for the other segment are charged to non-regulated labor expense.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below presents information about the reported revenues, operating income, net income, total assets and minority interests of our business segments.
| | For the years ended December 31, | |
| | 2005 | |
| | Regulated | | Other | | Eliminations | | Total | |
| | (000’s) | |
Statement of Income Information | | | | | | | | | | | |
Revenues | | $ | 360,428 | | $ | 26,450 | | | $ | (718 | ) | | $ | 386,160 | |
Operating income (loss) | | 53,754 | | (593 | ) | | — | | | 53,161 | |
Net income (loss) | | 24,865 | | (1,097 | ) | | — | | | 23,768 | |
Minority interest | | — | | (343 | ) | | — | | | (343 | ) |
Capital Expenditures | | 71,237 | | 2,619 | | | — | | | 73,856 | |
| | | | | | | | | | | | | | | |
| | 2004 | |
Statement of Income Information | | | | | | | | | | | |
Revenues | | $ | 304,265 | | $ | 21,935 | | | $ | (660 | ) | | $ | 325,540 | |
Operating income (loss) | | 53,299 | | (1,759 | ) | | — | | | 51,540 | |
Net income (loss) | | 23,681 | | (1,833 | ) | | — | | | 21,848 | |
Minority interest | | — | | 308 | | | — | | | 308 | |
Capital Expenditures | | 39,192 | | 2,700 | | | — | | | 41,892 | |
| | | | | | | | | | | | | | | |
| | 2003 | |
Statement of Income Information | | | | | | | | | | | |
Revenues | | $ | 304,922 | | $ | 21,218 | | | $ | (635 | ) | | $ | 325,505 | |
Operating income (loss) | | 62,371 | | (936 | ) | | — | | | 61,435 | |
Net income (loss) | | 30,843 | | (1,393 | ) | | — | | | 29,450 | |
Minority interest | | — | | (354 | ) | | — | | | (354 | ) |
Capital Expenditures | | 61,997 | | 3,908 | | | — | | | 65,905 | |
| | | | | | | | | | | | | | | |
| | As of December 31, | |
| | 2005 | |
| | Regulated | | Other | | Eliminations(1) | | Total | |
| | (000’s) | |
Balance Sheet Information | | | | | | | | | | | |
Total assets | | $ | 1,119,773 | | $ | 26,396 | | | $ | (24,139 | ) | | $ | 1,122,030 | |
Minority interest | | — | | (1,014 | ) | | — | | | (1,014 | ) |
| | | | | | | | | | | | | | | |
| | 2004 | |
Balance Sheet Information | | | | | | | | | | | |
Total assets | | $ | 1,023,619 | | $ | 25,296 | | | $ | (21,376 | ) | | $ | 1,027,539 | |
Minority interest | | — | | (705 | ) | | — | | | (705 | ) |
| | | | | | | | | | | | | | | |
(1) Reflects the elimination of the “Investment in subsidiary” recorded in the accounts of the regulated segment.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Selected Quarterly Information (Unaudited)
The following is a summary of previously reported quarterly results for 2005 and 2004. 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.
In the fourth quarter of 2005, we recorded income of approximately $0.5 million, net of taxes, to correct for the net impact of certain errors related to income taxes and jointly-owned plant pension accounting.
| | Quarters | |
| | First | | Second | | Third | | Fourth | |
| | (Dollars in thousands except per share amounts) | |
2005: | | | | | | | | | |
Operating revenues | | $ | 79,535 | | $ | 87,892 | | $ | 124,945 | | $ | 93,788 | |
Operating income | | 7,166 | | 10,530 | | 27,084 | | 8,381 | |
Net (loss) income | | (250 | ) | 3,158 | | 19,594 | | 1,266 | |
Basic earnings per share | | (0.01 | ) | 0.12 | | 0.75 | | 0.05 | |
Diluted earnings per share | | (0.01 | ) | 0.12 | | 0.75 | | 0.05 | |
| | | | | | | | | | | | | |
| | Quarters | |
| | First | | Second | | Third | | Fourth | |
| | (Dollars in thousands except per share amounts) | |
2004: | | | | | | | | | |
Operating revenues | | $ | 77,232 | | $ | 77,303 | | $ | 96,741 | | $ | 74,264 | |
Operating income | | 9,005 | | 9,558 | | 23,673 | | 9,304 | |
Net income | | 1,578 | | 2,078 | | 16,235 | | 1,957 | |
Basic earnings per share | | 0.06 | | 0.08 | | 0.64 | | 0.08 | |
Diluted earnings per share | | 0.06 | | 0.08 | | 0.63 | | 0.08 | |
| | | | | | | | | | | | | |
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.
As of December 31, 2005 and 2004, 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:
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THE EMPIRE DISTRICT ELECTRIC COMPANY
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Derivative Summary
| | 2005 | | 2004 | |
| | (In thousands) | |
Current assets | | $ | 8,639 | | $ | 2,867 | |
Noncurrent assets | | 23,891 | | 4,143 | |
Current liabilities | | (2,495 | ) | (1,030 | ) |
Noncurrent liabilities | | (907 | ) | (1,506 | ) |
Fair market value of derivatives (before tax) | | 29,128 | | 4,474 | |
Tax effect | | (11,098 | ) | (1,700 | ) |
Total OCI — per Balance Sheet | | $ | 18,030 | | $ | 2,774 | |
(Unrealized Gain — net of tax) | | | | | |
An $18.0 million net of tax, unrealized gain representing the fair market value of these derivative contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The tax effect of $11.1 million 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, 2006 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. Approximately $6.1 million is applicable to financial instruments which will settle within the next year. The increase in change in FMV of open contracts is due to the large price increase in futures prices due in part to the very active 2005 hurricane season.
We record 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.
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”:
| | December 31, 2005 | | December 31, 2004 | |
| | (In millions) | |
Overhedged Portion | | | ($1.0 | ) | | | $ | 0.7 | | |
Qualified Portion | | | $ | 4.4 | | | | $ | 11.5 | | |
| | | | | | | | | | | |
The table above does not include a $1.4 million realized loss from an interest rate derivative contract in June 2005. 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. We have instituted a process to determine if any future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.
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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:
| | December 31, | |
| | 2005 | | 2004 | |
| | (000’s) | |
Accounts receivable — other | | | | | |
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc. | | $ | 3,570 | | $ | 1,890 | |
Accounts receivable for insurance reimbursement for Energy Center(1) | | — | | 1,942 | |
Accounts receivable for non-regulated subsidiary companies | | 3,113 | | 3,062 | |
Accounts receivable from Westar Generating, Inc. for commonly-owned facility | | 690 | | 544 | |
Taxes receivable — overpayment of estimated income taxes | | 8,504 | | 4,151 | |
Accounts receivable for energy trading margin deposit(2) | | 2,104 | | — | |
Accounts receivable for true-up on maintenance contracts(3) | | 1,193 | | 1,199 | |
Other | | 123 | | 86 | |
Total accounts receivable — other | | $ | 19,297 | | $ | 12,874 | |
(1) The decrease of $1.9 million accounts receivable for insurance reimbursement for Energy Center relates to $4.1 million of total expenses for repairs to our Unit No. 2 combustion turbine at Energy Center, less our $1.0 million deductible which was expensed in the first quarter of 2004 and $3.1 million of insurance reimbursement received as of December 31, 2005 (of which $1.1 million had been received as of December 31, 2004).
(2) The $2.1 million accounts receivable for energy trading margin deposit represents the balance in our brokerage account as of December 31, 2005. NYMEX futures contracts are used in our hedging program of natural gas which require posting of margin.
(3) The $1.2 million in accounts receivable for true-up on maintenance contracts represents quarterly estimated credits due from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for State Line Combined Cycle Unit (SLCC). Forty percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of December 31, 2005.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 for all periods presented:
| | 2005 | | 2004 | | 2003 | |
| | (000’s) | |
Transmission and distribution expense | | $ | 8,124 | | $ | 7,441 | | $ | 8,081 | |
Power operation expense (other than fuel) | | 9,553 | | 9,984 | | 9,180 | |
Customer accounts & assistance expense | | 6,967 | | 7,099 | | 6,698 | |
Employee pension expense* | | 3,561 | | 3,019 | | 3,486 | |
Employee healthcare plan | | 8,687 | | 7,999 | | 6,809 | |
General office supplies and expense | | 6,792 | | 7,691 | | 6,268 | |
Administrative and general expense | | 8,564 | | 8,152 | | 8,118 | |
Allowance for uncollectible accounts | | 1,813 | | 1,456 | | 1,006 | |
Miscellaneous expense | | 107 | | 121 | | 107 | |
Total | | $ | 54,168 | | $ | 52,962 | | $ | 49,753 | |
* Does not include capitalized portion or amount deferred to a regulatory asset.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
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.
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, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 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 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None
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PART III
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 27, 2006, 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 has provided, and intends to continue to timely provide, the NYSE with the CEO’s Annual Certification.
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 27, 2006, which is incorporated herein by reference.
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 27, 2006, 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 four equity compensation plans, all of which have been approved by shareholders, the 1996 Stock Incentive Plan, the 2006 Stock Incentive Plan, the Employee Stock Purchase Plan and the Stock Unit Plan for Directors.
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The following table summarizes information about our equity compensation plans as of December 31, 2005.
Plan category | | | | (a) Number of securities
to be issued upon exercise
of outstanding options,
warrants and rights | | (b) Weighted-average
exercise price
of outstanding options,
warrants and rights(1) | | (c) Number of securities
remaining available
for future issuance
under equity compensation
plans (excluding securities
reflected in column (a)) | |
Equity compensation plans approved by security holders | | | 332,748 | | | | $ | 20.88 | | | | 1,827,316 | | |
Equity compensation plans not approved by security holders | | | — | | | | — | | | | — | | |
Total | | | 332,748 | | | | $ | 20.88 | | | | 1,827,316 | | |
(1) The weighted average exercise price of $20.88 relates to 39,100, 54,200 and 49,200 options granted to executive officers in 2005, 2004 and 2003 respectively, under the 1996 Stock Incentive Plan and 39,391 subscriptions outstanding for our Employee Stock Purchase Plan. These two plans had a weighted average exercise price of $20.84 and $21.03, respectively. There is no exercise price for 80,600 performance-based stock awards awarded under the 1996 Stock Incentive Plan or for the 70,257 units awarded under the Stock Unit Plan for Directors.
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 27, 2006, which is incorporated herein by reference.
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 27, 2006, which is incorporated herein by reference.
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PART IV
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 Registered Public Accounting Firm
Consolidated balance sheets at December 31, 2005 and 2004 | | 56 | |
Consolidated statements of income for each of the three years in the period ended December 31, 2005 | | 58 | |
Consolidated statements of comprehensive income for each of the three years in the period ended December 31, 2005 | | 59 | |
Consolidated statements of common shareholders’ equity for each of the three years in the period ended December 31, 2005 | | 60 | |
Consolidated statements of cash flows for each of the three years in the period ended December 31, 2005 | | 61 | |
Notes to consolidated financial statements | | 63 | |
Schedule for the years ended December 31, 2005, 2004 and 2003: | | | |
Schedule II — Valuation and qualifying accounts | | 112 | |
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
Exhibit
No. | | | Description | |
(3)(a) | | The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to Registration Statement No. 33-54539 on Form S-3). |
(b) | | By-laws of Empire as amended October 31, 2002 (Incorporated by reference to Exhibit 4(b) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368). |
(4)(a) | | Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto among Empire, The Bank of New York and State Street Bank and Trust Company of Missouri, N.A. (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368). |
(b) | | Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). |
(c) | | Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). |
(d) | | Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Form S-3, File No. 33-56635). |
(e) | | Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368). |
(f) | | Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368). |
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(g) | | Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368). |
(h) | | Twenty-Fifth Supplemental Indenture dated as of November 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(p) to Registration Statement No. 33-56635 on Form S-3). |
(i) | | Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for year ended December 31, 1996, File No. 1-3368). |
(j) | | Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File No. 1-3368). |
(k) | | Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank Minnesota, National Association (Incorporated by reference to Exhibit 4(v) to Registration Statement No. 333-87015 on Form S-3). |
(l) | | Securities Resolution No. 2, dated as of February 22, 2001, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-3368). |
(m) | | Securities Resolution No. 3, dated as of December 18, 2002, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368). |
(n) | | Securities Resolution No. 4, dated as of June 10, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K dated June 10, 2003 and filed June 29, 2003, File No. 1-3368). |
(o) | | Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for quarter ended September 30, 2003). |
(p) | | Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K filed on June 28, 2005, File No. 1-3368). |
(q) | | Rights Agreement dated as of April 27, 2000 between Empire and Mellon Investor Services LLC (Incorporated by reference to Exhibit 4 to Form 10-Q for the quarter ended March 31, 2000, File No. 1-3368). |
(r) | | $150,000,000 Unsecured Credit Agreement, dated as of July 15, 2005, among Empire, UMB Bank, N.A., as arranger and administrative agent, Bank of America, N.A., as syndication agent, and the lenders named therein (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-3368). |
(10)(a) | | 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639).† |
(b) | | 2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File No. 333-130075).† |
(c) | | Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1-3368).† |
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(d) | | The Empire District Electric Company Change in Control Severance Pay Plan and Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368).† |
(e) | | Amendment to The Empire District Electric Company Change in Control Severance Pay Plan and revised Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended June 30, 1996, File No. 1-3368).† |
(f) | | Form of Amendment to Severance Pay Agreement under The Empire District Electric Company Change in Control Severance Pay Plan and Forms of Agreement (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-3368)† |
(g) | | The Empire District Electric Company Supplemental Executive Retirement Plan. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for year ended December 31, 1994, File No. 1-3368).† |
(h) | | Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form 10-Q for quarter ended September 30, 1998, File No. 1-3368).† |
(i) | | Stock Unit Plan for Directors of The Empire District Electric Company.*† |
(j) | | Summary of Annual Incentive Plan.*† |
(k) | | Form of Notice of Award of Dividend Equivalents.*† |
(l) | | Form of Notice of Award of Non-Qualified Stock Options.*† |
(m) | | Form of Notice of Award of Performance-Based Restricted Stock.*† |
(n) | | Summary of Compensation of Non-Employee Directors.*† |
(12) | | Computation of Ratios of Earnings to Fixed Charges.* |
(21) | | Subsidiaries of Empire* |
(23) | | Consent of PricewaterhouseCoopers LLP* |
(24) | | Powers of Attorney.* |
(31)(a) | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
(31)(b) | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
(32)(a) | | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~ |
(32)(b) | | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~ |
† This exhibit is a compensatory plan or arrangement as contemplated by Item 15(a)(3) of Form 10-K.
* Filed herewith
~ This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.
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SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 2005, 2004 and 2003
| | | | Additions | | Deductions from reserve | | | |
| | | | | | Charged to Other Accounts | | | | | |
| | Balance At | | | | | | | | Balance at | |
| | Beginning | | Charged | | | | | | close of | |
| | of period | | to income | | Description | | Amount | | Description | | Amount | | period | |
Year ended December 31, 2005: | | | | | | | | | | | | | | | | | |
Reserve deducted from assets:
Accumulated provision for uncollectible accounts | | $ | 284,109 | | $ | 1,821,444 | | Recovery of
amounts previously
written off | | $ | 806,511 | | | Accounts
written off | | | $ | 2,350,256 | | $ | 561,808 | |
Reserve not shown separately in balance sheet:
Injuries and damages reserve (Note A) | | $ | 1,546,670 | | $ | 939,399 | | Property, plant &
equipment | | $ | 939,399 | | | Claims and
expenses | | | $ | 1,878,798 | | $ | 1,496,670 | |
Year ended December 31, 2004: | | | | | | | | | | | | | | | | | |
Reserve deducted from assets:
Accumulated provision for uncollectible accounts | | $ | 718,336 | | $ | 1,473,000 | | Recovery of
amounts previously
written off | | $ | 918,796 | | | Accounts
written off | | | $ | 2,826,023 | | $ | 284,109 | |
Reserve not shown separately in balance sheet:
Injuries and damages reserve (Note A) | | $ | 1,396,670 | | $ | 770,126 | | Property, plant &
equipment | | $ | 770,126 | | | Claims and
expenses | | | $ | 1,390,252 | | $ | 1,546,670 | |
Year ended December 31, 2003: | | | | | | | | | | | | | | | | | |
Reserve deducted from assets:
Accumulated provision for uncollectible accounts | | $ | 678,727 | | $ | 1,008,482 | | Recovery of
amounts previously
written off | | $ | 1,592,930 | | | Accounts
written off | | | $ | 2,561,803 | | $ | 718,336 | |
Reserve not shown separately in balance sheet:
Injuries and damages reserve (Note A) | | $ | 1,396,670 | | $ | 598,091 | | Property, plant &
equipment and | | $ | 598,091 | | | Claims and
expenses | | | $ | 1,196,182 | | $ | 1,396,670 | |
NOTE A: This reserve is provided for workers’ compensation, certain postemployment benefits and public liability damages. At December 31, 2005, 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”.
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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.
| THE EMPIRE DISTRICT ELECTRIC COMPANY |
Date: March 10, 2006 | By | /s/ WILLIAM L. GIPSON |
| | W. L. Gipson, President and
Chief Executive Officer |
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.
/s/ WILLIAM L. GIPSON | | March 10, 2006 |
William L. Gipson, President,
Chief Executive Officer, Director
(Principal Executive Officer) | | |
/s/ GREGORY A. KNAPP | | March 10, 2006 |
Gregory A. Knapp, Vice President-Finance
(Principal Financial Officer) | | |
/s/ LAURIE A. DELANO | | March 10, 2006 |
Laurie A. Delano, Controller, Assistant
Secretary and Assistant Treasurer
(Principal Accounting Officer) | | |
/s/ DR. JULIO S. LEON* | | March 10, 2006 |
Dr. Julio S. Leon, Director | | |
/s/ KENNETH R. ALLEN* | | March 10, 2006 |
Kenneth R. Allen, Director | | |
/s/ MYRON W. MCKINNEY* | | March 10, 2006 |
Myron W. McKinney, Director | | |
/s/ ROSS C. HARTLEY* | | March 10, 2006 |
Ross C. Hartley, Director | | |
/s/ D. RANDY LANEY* | | March 10, 2006 |
D. Randy Laney, Director | | |
/s/ BILL D. HELTON* | | March 10, 2006 |
Bill D. Helton, Director | | |
/s/ B. THOMAS MUELLER* | | March 10, 2006 |
B. Thomas Mueller, Director | | |
/s/ ALLAN T. THOMS* | | March 10, 2006 |
Allan T. Thoms, Director | | |
/s/ MARY McCLEARY POSNER* | | March 10, 2006 |
Mary McCleary Posner, Director | | |
/s/ GREGORY A. KNAPP | | |
*By (Gregory A. Knapp, As attorney in fact
for each of the persons indicated) | | |
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