EMPIRE DISTRICT ELECTRIC CO - 10-K Annual Report

Kansas

44-0236370

(State of Incorporation)

(I.R.S. Employer Identification No.)

602 Joplin Street, Joplin, Missouri

(Address of principal executive offices)

(zip code)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004 or

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)

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 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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes x No o

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, 2004, was approximately $512,892,358.

As of February 28, 2005, 25,740,813 shares of common stock were outstanding.

The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:

TABLE OF CONTENTS

		Page
	Forward Looking Statements	3
PART I
ITEM 1.	BUSINESS	4
	General	4
	Electric Generating Facilities and Capacity	4
	Construction Program	6
	Fuel	6
	Employees	8
	Electric Operating Statistics	9
	Executive Officers and Other Officers of Empire	10
	Regulation	10
	Environmental Matters	11
	Conditions Respecting Financing	13
	Our Website	13
ITEM 2.	PROPERTIES	14
	Electric Facilities	14
	Water Facilities	15
	Other	15
ITEM 3.	LEGAL PROCEEDINGS	15
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	16
PART II
ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	16
ITEM 6.	SELECTED FINANCIAL DATA	17
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
	Executive Summary	18
	Results of Operations	19
	Liquidity and Capital Resources	29
	Contractual Obligations	33
	Off-Balance Sheet Arrangements	33
	Critical Accounting Policies	33
	Recently Issued Accounting Standards	36
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	37
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	78
ITEM 9A.	CONTROLS AND PROCEDURES	77
ITEM 9B.	OTHER INFORMATION	78
PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	79
ITEM 11.	EXECUTIVE COMPENSATION	79
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	79
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	80
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	80
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	81
	SIGNATURES	85

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, 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;

matters such as the effect of changes in credit ratings on the availability and our 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.

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 2004, 93.0% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.6% from our non-regulated businesses.

The 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 2004 retail electric revenues, approximately 88.7% came from Missouri customers, 5.6% from Kansas customers, 3.2% from Oklahoma customers and 2.5% 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 48% of our electric operating revenues in 2004 were derived from incorporated communities with franchises having at least ten years remaining and approximately 21% 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 2004 were derived as follows: residential 41%, commercial 31%, industrial 17%, wholesale on-system 4.5%, wholesale off-system 2% and other 4.5%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2004 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 2% of electric revenues in 2004.

Our non-regulated businesses, which we operate through our wholly-owned subsidiary EDE Holdings, Inc., include leasing of fiber optics cable and equipment (which we are also using in our own operations), and 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.

Electric Generating Facilities and Capacity

At December 31, 2004, our generating plants consisted of:

Plant
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 described below).

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 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, 2005. 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 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 rules. The SPP requires its members to maintain a minimum 12% capacity margin. We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. We had short-term contracts for the purchase of firm energy with American Electric Power (AEP) from January 2002 through June 2003. 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.

On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed Elk River Windfarm which will be located in Butler County, Kansas. We anticipate purchasing approximately 550,000 megawatt-hours of energy annually from the project beginning in December 2005. On January 24, 2005, Flint Hills Tallgrass Prairie Heritage Foundation, Inc. filed a purported class action complaint in the United States District Court (the Court) seeking to halt the development or operation of industrial wind turbine electric power generation facilities within the Flint Hills Tallgrass Prairie Ecosystem. This complaint was dismissed with prejudice by the Court on February 11, 2005. A notice of appeal has been filed. See Item 3, “Legal Proceedings”. On February 4, 2005, we filed an application with the Missouri Public Service Commission to initiate a process to obtain a certificate of convenience and necessity to participate in a proposed steam electric generating station in Platte County, Missouri (Iatan Unit 2), and in connection therewith, obtain approval of an Experimental Regulatory Plan that will provide adequate assurance to potential investors concerning this, or other baseload generation options. We are considering owning up to 200 MWs of the 800-900 MW Iatan Unit 2, although we are not committed to own any of the unit at this time and have not received any proposed contractual documents from KCP&L. Our forecasted customer growth indicates we will be below the SPP’s 12% minimum capacity requirement beginning in 2007. As a result, we have purchased, and will install at our Riverton facility, a Siemens V84.3A2 combustion turbine with an expected summer capacity of 155 megawatts to be operational in 2007.

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 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 new windfarm and the proposed Iatan Unit 2 project, however, are not 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
2004	162	1102	1264
2005	162	1102	1264
2006	162	1102	1264
2007	162	1257	1419
2008	162	1257	1419
2009	162	1257	1419

The charges for capacity purchases under the Westar contract referred to above during calendar year 2004 amounted to approximately $16.2 million. Minimum charges for capacity purchases under the Westar contract total approximately $97.1 million for the period June 1, 2004, through May 31, 2010.

The maximum hourly demand on our system reached a record high of 1,041 megawatts on August 25, 2003. Our previous record peak of 1,001 megawatts was established in August 2001. The maximum hourly winter demand

of 987 megawatts was set on January 23, 2003. Our previous winter peak of 941 megawatts was established on December 19, 2000. Our 2004 peak was 1,014 megawatts established on August 3, 2004.

Construction Program

Total gross property additions (including construction work in progress) for the three years ended December 31, 2004, amounted to $184.4 million and retirements during the same period amounted to $14.9 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 $41.4 million in 2004 and for the next three years are estimated for planning purposes to be as follows:

	Estimated Capital Expenditures (amounts in millions)
	2005		2006		2007		Total
New generating facilities	$	21.7	$	30.7	$	29.9	$	82.3
Additions to existing generating facilities		11.4		12.3		17.7		41.4
Transmission facilities		1.8		6.0		5.4		13.2
Distribution system additions		26.5		26.9		27.4		80.8
Non-regulated additions		2.7		2.4		2.4		7.5
General and other additions		5.2		7.7		5.6		18.5
Total	$	69.3	$	86.0	$	88.4	$	243.7

Additions to our transmission and distribution systems to meet projected increases in customer demand and construction expenditures for new generating facilities constitute the majority of the projected capital expenditures for the three-year period listed above, including approximately $16.9 million in 2005, $13.5 million in 2006 and $14.1 million in 2007 for the purchase and installation at our Riverton facility of the planned Siemens V84.3A2 combustion turbine with an expected capacity of 155 megawatts. Our estimated capital expenditures for 2005 and 2006 have increased over previously estimated amounts due to the reallocation of $14 million of new generation expenditures that had been anticipated to be spent in 2004 but were not.

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

Coal supplied approximately 70.5% of our total fuel requirements in 2004 based on kilowatt-hours generated. The remainder was supplied by natural gas (28.7%) with oil and tire-derived fuel (TDF), which is produced from discarded passenger car tires, providing the remaining 0.8%. 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 anticipate purchasing approximately 550,000 megawatt-hours of energy, or 10% of our annual needs, from the project beginning in December 2005. We anticipate the cost of this contract to also be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation.

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 2004, Asbury burned a coal blend consisting of approximately 90.3% Western coal (Powder

River Basin) and 9.7% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2004, we had sufficient coal on hand to supply anticipated requirements at Asbury for 93 days. This extra inventory was due to coal purchased over and above our contractual obligations in order to take advantage of favorable market conditions and for test burns conducted during 2004.

Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas and oil. During 2004 Riverton burned 100% Western coal (Powder River Basin) on Unit No. 8 and a blend consisting of approximately 75% Western coal (Powder River Basin) and 25% blend coal on Unit No. 7 on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. As of December 31, 2004, we had coal supplies on hand to meet anticipated requirements at the Riverton Plant for 60 days.

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 new, three-year contract with Peabody on December 15, 2004 that covers approximately 100% of our anticipated 2005 Western coal requirements, approximately 67% of our anticipated 2006 Western coal requirements and approximately 33% of our anticipated 2007 Western coal requirements. This Peabody coal is supplied from the Rochelle/North Antelope mines located in Campbell County, Wyoming, and is shipped to the Asbury Plant by rail, a distance of approximately 800 miles. The coal is delivered under a transportation contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which expires at the end of June 2005. In 2004 we accepted a binding proposal and are in the process of finalizing contractual terms and conditions on a new transportation contract. We expect that, beginning in July 2005, this coal will be delivered under the new transportation contract. The delivered price of coal is expected to be higher than the 2004 price during the first and second quarters of 2005, but we expect the delivered price increase to be substantially mitigated beginning in the third quarter of 2005 due to a combination of our new coal supply and coal transportation contracts. We are currently leasing one 125-car aluminum unit train, which delivers Peabody coal to the Asbury Plant. The Peabody 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. The Phoenix coal is 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 Kansas City Power & Light (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 2005, approximately 90% for 2006, approximately 75% for 2007 and approximately 20% for 2008. 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 being used as a backup fuel. In April 2003, two 50 megawatt FT8 peaking units were placed into commercial operation at the Energy Center. During 2004, fuel consumption at the Energy Center was 88.1% natural gas with the remaining 11.9% being oil based on kilowatt hours generated. State Line fuel consumption during 2004 was 100% natural gas. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation on Units No. 1 and 2. As of December 31, 2004, we have oil inventories sufficient for approximately five and one half days of full load operation for these two units at the Energy Center and five days of full load operation for State Line Unit No. 1. The two new peaking units at the Energy Center are currently designed with a day tank for fuel oil storage, which allows both units to operate at full load for approximately one day.

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 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. Our transportation agreement was originally with Williams Natural Gas Company (Williams). In 2002, we signed a precedent agreement with Williams (now Southern Star Central), which upon completion of necessary upgrades to the natural gas pipeline system in September 2004, will provide 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 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:

	2004		2003		2002
Coal — Iatan	$	0.726	$	0.750	$	0.811
Coal — Asbury		1.179		1.155		1.125
Coal — Riverton		1.309		1.307		1.264
Natural Gas		4.451		3.651		3.280
Oil		6.842		5.575		5.300

Our weighted cost of fuel burned per kilowatt-hour generated was 1.885 cents in 2004, 1.686 cents in 2003 and 1.652 cents in 2002.

Employees

At December 31, 2004, we had 855 full-time employees, including 174 employees of Mid-America Precision Products (MAPP), of which we own a 50.01% 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 new four-year labor agreement effective retroactively to November 1, 2002.

ELECTRIC OPERATING STATISTICS⁽¹⁾

	2004		2003		2002		2001		2000
Electric Operating Revenues (000s):
Residential	$	124,394	$	125,197	$	126,088	$	110,584	$	108,572
Commercial		92,407		90,577		91,065		82,237		77,601
Industrial		51,861		50,643		50,155		44,509		42,711
Public authorities		7,441		7,210		7,099		6,311		5,927