UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

(Mark One)

 

 

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:

 

 

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 ý  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. [   ]

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).   Yes  ý  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 28, 2002, was approximately $459,862,868.

 

As of January 31, 2003, 22,595,071 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 2002 Annual Meeting of		Part of Item 12 of Part III
	Stockholders to be held on April 24, 2003.		All of Item 13 of Part III

 

 

TABLE OF CONTENTS

 

	Forward Looking Statements
PART I
ITEM 1.	BUSINESS
	General
	Electric Generating Facilities and Capacity
	Construction Program
	Fuel
	Employees
	Electric Operating Statistics
	Executive Officers and Other Officers of Empire
	Regulation
	Environmental Matters
	Conditions Respecting Financing
	Our Website
ITEM 2.	PROPERTIES
	Electric Facilities
	Water Facilities
	Other
ITEM 3.	LEGAL PROCEEDINGS
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
ITEM 6.	SELECTED FINANCIAL DATA
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Results of Operations
	Liquidity and Capital Resources
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL  DISCLOSURE
PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.	EXECUTIVE COMPENSATION
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14.	CONTROLS AND PROCEDURES
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, REPORTS ON FORM 8-K
SIGNATURES
CERTIFICATIONS

 

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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, competition, litigation, our construction program, 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 and timing of rate relief we are currently seeking 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; 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 and our becoming a participant in a Regional Transmission Organization; changes in accounting requirements; other circumstances affecting anticipated rates, revenues and costs, including our cost of funds; the revision of our construction plans and cost estimates; the performance of projects undertaken by our non-regulated businesses; the success of efforts to invest in and develop new opportunities; and costs and effect 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.

 

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 several non-regulated businesses. In 2002, 96.3% of our gross operating revenues were provided from the sale of electricity, 0.3% from the sale of water and 3.4% came 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 are light industry, agriculture and tourism. Of our total 2002 retail electric revenues, approximately 88% came from Missouri customers, 6% from Kansas customers, 3% from Oklahoma customers and 3% from Arkansas customers.

 

We supply electric service at retail to 119 incorporated communities and to various unincorporated areas and at wholesale to four municipally owned distribution systems and two rural electric cooperatives. 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 49% of our electric operating revenues in 2002 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.

 

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Our electric operating revenues in 2002 were derived as follows: residential 41%, commercial 29%, industrial 16%, wholesale on-system 4%, wholesale off-system 5.5% and other 4.5%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2002 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 1% of electric revenues in 2002.

 

We made an investment of approximately $2.0 million in 2002 and $0.8 million in 2001 in fiber optics cable and equipment which we are using in our own operations and leasing to other entities. We also offer Internet access, utility training, close-tolerance custom manufacturing, surge suppressors and other energy services. We created a wholly owned subsidiary in 2001, EDE Holdings, Inc., to hold our non-regulated companies. EDE Holdings is a holding company which currently owns: 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 the Internet-based customer information system software formerly named Centurion that was developed by Empire employees; a 100% interest in Southwest Energy Training that offers technical training to the utility industry; a 100% interest in Transaeris, a wireless Internet provider and a controlling 50.01% interest in Mid-America Precision Products, 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. On February 1, 2003 we purchased Joplin.com, a leading Internet service provider in the Joplin, Missouri area. The purchase was made through Transaeris. We are merging Transaeris and Joplin.com into one company named Fast Freedom, Inc. We sold our monitored security business, E-Watch, to Federal Protection, Inc. of Springfield, Missouri in December 2002 after it did not meet our earnings expectations.

 

Electric Generating Facilities and Capacity

 

At December 31, 2002, our generating plants consisted of:

 

Plant		Capacity (megawatts)			Primary Fuel
Asbury		213			Coal
Riverton		136			Coal
Iatan (12% ownership)		80			Coal
State Line Combined Cycle (60% ownership)		300			Natural Gas
Empire Energy Center		169			Natural Gas
State Line Unit No. 1		90			Natural Gas
Ozark Beach		16			Hydro
Total		1,004

 

On October 25, 2001, we entered into an agreement with P2 Energy to purchase two FT8 peaking units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. Both units have been delivered and are scheduled to be operational in the second quarter of 2003. See Item 2, “Properties - Electric Facilities” for further information about these plants.

 

We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council. Effective September 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. We have been participating with other utility members in an effort to restructure the SPP to make it a regional transmission organization (RTO). On October 19, 2001, the SPP and Midwest Independent Transmission System Operator, Inc. (MISO) announced an agreement for the consolidation of the two organizations. In December 2001, the Federal Energy Regulatory Commission (FERC) approved this newly formed MISO as the first RTO. The agreement to consolidate was completed in February 2002. MISO filed the necessary documents with the FERC on March 29, 2002 and the consolidation is still in progress. On November 1, 2002, MISO and SPP filed a combined tariff for the new resulting company as directed by the FERC. The FERC conditionally accepted the filing on December 19, 2002. We have filed with the FERC and the utility commissions in the four states in which we operate to transfer control over the operation of our transmission facilities to MISO. The Kansas Corporation Commission and the FERC have approved our requests while the filings in Missouri and Arkansas are still pending. Although we were not required to file in Oklahoma, we did a courtesy filing for informational purposes. If the consolidation does not occur, we may operate our transmission separately while evaluating

 

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which RTO to join. 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. We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. We also have a short-term contract for the purchase of firm energy with American Electric Power (AEP) from January 2003 through March 31, 2003. In 2002, we had similar short-term contracts with AEP that ran from January 2002 through December 2002. The amount of capacity purchased under these 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. 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). We currently expect to purchase additional capacity to meet reserve margins in 2007 of 10 to 50 megawatts based on the current forecast of load.

 

 

*Does not include AEP contracts.

**Includes capacity from the two FT8 peaking units scheduled for completion in the second quarter of 2003.

 

The charges for capacity purchases under the Westar contract referred to above during calendar year 2002 amounted to approximately $16.2 million. Minimum charges for capacity purchases under the Westar contract total approximately $80.9 million for the period June 1, 2002, through May 31, 2007.

 

The maximum hourly demand on our system reached a record high of 1001 megawatts on August 9, 2001. Our previous record peak of 993 megawatts was established in August 2000. A new 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.

 

Construction Program

Total gross property additions (including construction work in progress) for the three years ended December 31, 2002, amounted to $277.4 million and retirements during the same period amounted to $32.5 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 construction-related expenditures, including allowance for funds used during construction (AFUDC) were $73.7 million in 2002 and for the next three years are estimated for planning purposes (including AFUDC) to be as follows:

 

 

5

 

Our projected construction expenditures for new generating facilities include the two FT8 peaking units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. Both units have been delivered and are scheduled to be operational in the second quarter of 2003. The cost for the purchase, construction and installation of these units was approximately $31.7 million (including AFUDC) in 2002 and is estimated to be approximately $22.0 million (including AFUDC) in 2003. An initial payment of $3.4 million was made in 2001 when we entered into the purchase agreement for the units. Additions to our transmission and distribution systems to meet projected increases in customer demand constitute the majority of the remainder of the projected construction expenditures for the three-year period listed above.

 

We had originally estimated that our construction expenditures (including AFUDC) would total approximately $71 million in 2003, $67 million in 2004 and $76 million in 2005. These estimates were reduced based on the following factors: (1) a Missouri Commission approved change in policy relating to charging developers for new line construction, which will reduce our costs, (2) an expected change in Missouri’s EPA approved plan for nitrogen oxide (NOx) reduction, which will allow us to delay additional environmentally related construction and (3) a revision of our annual customer growth projections from 1.6% to 1.4% (based on updated historical growth reflecting lowered economic activity) over the next several years, which will allow us to delay construction of additional generation capacity. We had initially projected additions to existing generating facilities to include $6.4 million in 2003 and $10.3 million in 2004 for the installation of a selective catalytic reduction system at the Asbury Plant to comply with nitrogen oxide (NOx) emission standards set by the Missouri Department of Natural Resources. However, the anticipated change in Missouri’s EPA approved plan for NOx reduction has allowed us to delay this construction. See “- Environmental Matters” below for more information.

 

Estimated construction 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 construction 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 74.5% of our total fuel requirements in 2002 based on kilowatt-hours generated. The remainder was supplied by natural gas (25.1%) with oil generation and tire-derived fuel (TDF), which is produced from discarded passenger car tires, providing less than 1%. We expect that the amount and percentage of electricity generated by natural gas will increase due to the combined cycle unit at the State Line Power Plant that was placed into commercial operation in June 2001 and the addition of the two 50 megawatt FT8 peaking units currently being installed at the Empire Energy Center and scheduled to be operational by the second quarter of 2003.

 

Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel and TDF being used as a supplement fuel. Asbury is currently burning a coal blend consisting of approximately 92% Western coal (Powder River Basin) and 8% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2002, we had sufficient coal on hand to supply anticipated requirements at Asbury for 100 days. This extra inventory was due to coal contract commitments to purchase a minimum tonnage for the year.

 

Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas and oil. Riverton is currently burning 100% Western coal (Powder River Basin) on Unit No. 8 and a blend consisting of approximately 78% Western coal (Powder River Basin) and 22% 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, 2002, we had coal supplies on hand to meet anticipated requirements at the Riverton Plant for 65 days.

 

We have a long-term contract, expiring in December 2004, with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal (Powder River Basin) at the Asbury and Riverton Plants during the term of the contract. 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

 

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approximately 800 miles. The coal is delivered under a transportation contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company. 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. Asbury blend coal was supplied during 2002 under a short-term contract, which expired December 31, 2002, with GENWAL Resources, Inc. Beginning in September 2003, this coal will be supplied by Phoenix Coal Sales, Inc. under a five-year contract expiring December 31, 2007 and will be transported by truck. Asbury currently has enough blend coal supplied under the previous contract with GENWAL to supply its needs until the new mine begins delivering coal. The Riverton Plant blend coal is currently being supplied under the same contract with Phoenix Coal Sales, Inc. The Phoenix coal is transported to Riverton via truck.

 

Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by Kansas City Power & Light (70%), Aquila (18%) and us (12%). Low sulfur Western coal in quantities sufficient to meet substantially all of Iatan’s requirements is supplied under a long-term contract expiring on December 31, 2003, between the joint owners and the Thunder Basin Coal Company. Kansas City Power & Light is the operator of this plant and is responsible for arranging its fuel supply. The coal is transported by rail under a contract expiring on December 31, 2010, with the Burlington Northern and Santa Fe Railway Company and The Kansas City Southern Railway Company.

 

Since 1995, our Energy Center and State Line combustion turbine facilities have been fueled primarily by natural gas with oil being used as a backup fuel. During 2002, the heat input at the Energy Center was 99% natural gas with less than 1% being oil. The State Line heat input during 2002 was 100% natural gas. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation. We currently have oil inventories sufficient for approximately nine days of full load operation for the Energy Center and eight days of full load operation for State Line Unit No. 1.

 

We have a firm agreement with Southern Star Central Pipeline, Inc. expiring July 31, 2016, for the transportation of natural gas to the State Line Power Plant for State Line Unit No. 1 and the jointly-owned Combined Cycle Unit. This transportation agreement can also supply natural gas to 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, which upon completion of necessary upgrades to the natural gas pipeline system (expected to be in June 2003) will grant us additional transportation capability through May 31, 2017. In 2002, Williams sold their Central Pipeline assets (including our natural gas transportation agreements) to Southern Star Central Pipeline, Inc. We expect that our remaining gas transportation requirements, as well as the majority of our natural gas supply requirements, will be met by short-term forward contracts and spot purchases.

 

The following table sets forth a comparison of the costs, including transportation costs, per million Btu of various types of fuels used in our facilities:

 

 

Our weighted cost of fuel burned per kilowatt-hour generated was 1.651 cents in 2002, 2.048 cents in 2001 and 1.846 cents in 2000.

 

Employees

At December 31, 2002, we had 792 full-time employees, including 148 Mid-America Precision Products employees. 320 of these employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). Our three-year agreement with the Local 1474 of the IBEW expired on October 31, 2002. Negotiations with the IBEW have not resulted in a new agreement, but are continuing. However, pursuant to its terms, the contract was automatically renewed for an additional year with both the IBEW and us having the right to submit any unresolved issues to binding arbitration.

 

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ELECTRIC OPERATING STATISTICS (1)

 

		2002			2001			2000			1999			1998
Electric Operating Revenues (000s):
Residential		$	126,088		$	110,584		$	108,572		$	98,787		$	100,567
Commercial		91,065			82,237			77,601			73,773			71,810
Industrial		50,155			44,509			42,711			41,030			39,805
Public authorities		7,099			6,311			5,927			5,847			5,559
Wholesale on-system		11,868			12,911			11,738			10,682			10,928
Miscellaneous		6,987			5,583			4,546			3,856			4,006
Total system		293,262			262,135			251,095			233,975			232,675
Wholesale off-system		17,185			3,898			7,842			7,090			6,126
Less Provision for IEC Refunds		15,875			2,843			—			—			—
Total electric operating revenues		294,572			263,190			258,937			241,065			238,801
Electricity generated and purchased (000s of Kwh):
Steam		2,143,323			1,969,412			2,193,847			2,378,130			2,228,103
Hydro		45,430			53,635			51,132			86,349			70,631
Combustion turbine		943,924			790,993			455,678			520,340			439,517
Total generated		3,132,677			2,814,040			2,700,657			2,984,819			2,738,251
Purchased		2,520,421			2,092,955			2,255,076			1,686,782			1,970,348
Total generated and purchased		5,653,098			4,906,995			4,955,733			4,671,601			4,708,599
Interchange (net)		(69		)	(264		)	145			(138		)	(1,894		)
Total system input		5,653,029			4,906,731			4,955,878			4,671,463			4,706,705
Maximum hourly system demand (Kw)		987,000			1,001,000			993,000			979,000			916,000
Owned capacity (end of period) (Kw)		1,004,000			1,007,000			878,000			878,000			878,000
Annual load factor (%)		56.88			54.75			55.12			52.16			55.72
Electric sales (000s of Kwh):
Residential		1,726,449			1,681,085			1,660,928			1,509,176			1,548,630
Commercial		1,378,165			1,375,620			1,333,310			1,260,597			1,246,323
Industrial		1,027,446			1,004,899			1,015,779			988,114			960,783
Public authorities		101,188			100,125			96,403			99,739			98,675
Wholesale on-system		323,103			322,336			309,633			297,614			299,256
Total system		4,556,352			4,484,065			4,416,053			4,155,240			4,153,667
Wholesale off-system		735,154			105,975			161,293			198,234			235,391
Total electric sales		5,291,506			4,590,040			4,577,346			4,353,474			4,389,058
Company use (000s of Kwh)		9,960			10,134			8,714			8,583			8,940
Lost and unaccounted for (000s of Kwh)		351,563			306,557			369,818			309,406			308,707
Total system input		5,653,029			4,906,731			4,955,878			4,671,463			4,706,705
Customers (average number of monthly bills rendered):
Residential		127,681			125,996			123,618			121,523			119,265
Commercial		22,858			22,670			22,504			22,206			21,774
Industrial		349			337			345			350			354
Public authorities		1,690			1,645			1,674			1,759			1,739
Wholesale on-system		7			7			7			7			7
Total system		152,585			150,655			148,148			145,845			143,139
Wholesale off-system		16			7			6			6			6
Total		152,601			150,662			148,154			145,851			143,145
Average annual sales per residential customer (Kwh)		13,522			13,342			13,436			12,419			12,985
Average annual revenue per residential customer		$	936.21		$	869.72		$	878.29		$	812.91		$	843.22
Average residential revenue per Kwh		6.92		¢	6.52		¢	6.54		¢	6.55		¢	6.49		¢
Average commercial revenue per Kwh		6.21		¢	5.91		¢	5.82		¢	5.85		¢	5.76		¢
Average industrial revenue per Kwh		4.55		¢	4.35		¢	4.20		¢	4.15		¢	4.14		¢

 

(1) See Item 6 - Selected Financial Data for additional financial information regarding Empire.

 

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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, 2002, positions held and effective date of such positions are presented below. All of our officers, other than G. A. Knapp, B. P. Beecher and R. F. Gatz (whose biographical information is set forth below), have been employed by Empire for at least the last five years.

 

Name		Age at 12/31/02		Positions with the Company		With the Company since		Officer since
W. L. Gipson(1)		45		President and Chief Executive Officer (2002), Executive Vice President and Chief Operating Officer (2001), Vice President – Commercial Operations (1997), General Manager (1997), Director of Commercial Operations (1995), Economic Development Manager (1987)		1981		1997
B. P. Beecher(2)		37		Vice President – Energy Supply (2001), General Manager – Energy Supply (2001)		2001		2001
R. F. Gatz(3)		52		Vice President – Strategic Development (2002), Vice President – Nonregulated Services (2001), General Manager – Nonregulated Services (2001)		2001		2001
D. W. Gibson(4)		56		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
G. A. Knapp(5)		51		Vice President – Finance and Chief Financial Officer (2002), General Manager – Finance (2002)		2002		2002
M. E. Palmer		46		Vice President – Commercial Operations (2001), General Manager – Commercial Operations (2001), Director of Commercial Operations (1997), District Manager of Customer Services (1994)		1986		2001
J. S. Watson		50		Secretary-Treasurer (1995), Accounting Staff Specialist (1994)		1994		1995
D. L. Coit		52		Controller and Assistant Treasurer (2000) and Assistant Secretary (2001), Manager Property Accounting (1983)		1971		2000

 

(1) W. L. Gipson became President and Chief Executive Officer effective May 1, 2002 and was elected to the Board of Directors in April 2002.

(2) B. 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.

(3) R. F. Gatz was previously with Hook Up, Inc. from 1999 to 2001 as Chief Administrative Officer and with Mercantile Bank in Joplin from 1985 to 1999 and held the positions of Executive Vice President, Senior Credit Officer, and Chief Financial Officer. His current title was changed in 2002 from Vice President - Nonregulated Services to Vice President - Strategic Development.

(4) Effective March 15, 2002, Dave Gibson became Vice President – Regulatory Services. Effective July 1, 2002, he became Vice President – Regulatory and General Services.

(5) Effective March 15, 2002. G. 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.

 

Regulation

General. As a public utility, we are subject to the jurisdiction of the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma and the Arkansas Public Service Commission 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 Kansas Commission also has jurisdiction over the issuance of securities. 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 - Results of Operations - Competition.”

 

Our Ozark Beach Hydroelectric Plant is operated under a license from FERC. See Item 2, “Properties - Electric Facilities.” We are disputing a Headwater Benefits Determination Report we received from FERC on September 9, 1991. The report calculates an assessment to us for headwater benefits received at the Ozark Beach Hydroelectric Plant for the period 1973 through 1990 in the amount of $705,724, and calculates an

 

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annual assessment thereafter of $42,914 for the years 1991 through 2011. We believe that the methodology used in making the assessment was incorrect and contested the determination. As of December 31, 2002, the FERC had not responded to the comments filed by us on July 31, 1992. We are currently accruing an amount monthly equal to what we believe the correct assessment to be.

 

During 2002, approximately 88% of our electric operating revenues were received from retail customers. Approximately 88%, 6%, 3% and 3% of such retail revenues were derived from sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 10% of our electric operating revenues during 2002.

 

Rates. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating Revenues and Kilowatt-Hour Sales — Rate Matters” for information concerning recent electric rate proceedings.

 

Fuel Adjustment Clauses. Fuel adjustment clauses permit changes in fuel costs to be passed along to customers without the need for a rate proceeding. Automatic fuel adjustment clauses are presently applicable to retail electric sales in Oklahoma and system wholesale kilowatt-hour sales under FERC jurisdiction. We have implemented an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis. We do not have a fuel adjustment clause in Missouri or Kansas.

 

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 the new 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 oxide (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 both SO2 and NOx on January 1, 1995. 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. The two new FT8 peaking units at the Empire Energy Center, which are expected to be completed in the second quarter of 2003, will become affected units when they are placed in service.

 

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, utilities or “banked” for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (EPA) withholds annually a percentage of the emission allowances awarded to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these allowances.

 

Our Asbury, Riverton and Iatan plants currently burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur local coal or burn 100% low sulfur Western coal. The State Line Plant and the new aero units are gas-fired facilities and do not receive SO2 allowances. However, annual allowance requirements for the State Line Plant and the new FT8 peaking units, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. We anticipate, based on current operations, that the combined actual SO2 allowance need for all affected plant facilities will not exceed the number of allowances awarded to us annually by the EPA. The excess annual SO2 allowances will be transferred to our inventoried bank of allowances. We currently have 50,000 banked allowances.

 

NOx Emissions. The Asbury Plant is in compliance with current NOx requirements. The 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, which has a cyclone-fired boiler, received permission from the Missouri Department of Natural Resources to burn tire derived fuel at a maximum rate of 2% of total fuel input. During

 

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2002, approximately 3,400 tons of TDF were burned. This is equivalent to 340,000 discarded passenger car tires.

 

In April 2000 the Missouri Department of Natural Resources 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 0.35lbs/mmBtu for Western Missouri. The Iatan, Asbury, State Line and Energy Center facilities are affected by this regulation. The current compliance date is set for May 1, 2003. The Iatan, State Line and Energy Center units, including the new FT8 peaking units, presently meet this emission limit. The Asbury Plant does not. The Missouri NOx Rule provides for a NOx emission trading program and for the generation of Early Reduction Credits (ERCs) during the years 2000, 2001 and 2002. ERCs may be used for compliance during 2003 and 2004. However, on December 4, 2002 the Missouri Department of Natural Resources filed proposed amendments to the Missouri NOx Rule with the Missouri Secretary of State’s Office. Approval of these amendments by the Missouri Air Conservation Commission is tentatively scheduled for April 2003. These amendments include provisions for the delay of compliance with the Missouri NOx Rule until May 1, 2004. Also included are amendments to extend ERC generation to 2003, ERC usage to 2005 and a NOx limit of 0.68 lbs/mmBtu for cyclone-fired boilers burning TDF. In addition, a law that establishes a NOx emission rate during the year 2003 of 0.68 lbs/mmBtu for certain boilers burning TDF was passed by the Missouri Legislature during the 2002 legislative session and signed by the Governor. The Asbury Plant qualifies for the 0.68 lbs/mmBtu NOx emission rate. We are following all regulatory developments and evaluating our options at this time. NOx trading and the purchase of ERCs, as described under “Business - Construction Program”, may permit the delay of the installation of major NOx controls at Asbury until 2008.

 

Due to the uncertainty of the national regulatory and legislative actions predicted for 2003, it is impossible to accurately forecast estimated compliance costs associated with the various sections of the Clean Air Act Amendment under Title I of the 1990 Amendments or to forecast the substance of multi-emission legislation that may exempt electric utilities from some or all of the Title I programs.

 

We have operating permits for our State Line Power Plant and have continuously operated in compliance with those permits since they went into operation on May 30, 1995 for Unit No. 1 and June 18, 1997 for Unit No. 2. In July 2000, we received a request for information from the EPA regarding the State Line Power Plant. The information request indicated that the State Line Power Plant units should have an Acid Rain Permit under Title IV of the 1990 Amendments in addition to the construction and operating permits previously issued to us by the Missouri Department of Natural Resources. In response, in August 2000, we applied for the required Acid Rain Permit with the Missouri Department of Natural Resources and subsequently received the required permit. The EPA notified us in June 2001 that we were subject to being fined approximately $173,000 because of the lack of the permit but had the right to request a hearing or a settlement conference. We had a settlement conference with the EPA in July 2001. The EPA offered to settle if we agreed to a $35,000 fine and to undertake a supplemental environmental project with a cost approximating $146,000. The supplemental environmental project was physically completed in October 2002 and final documentation to conclude this matter was submitted to the EPA in November 2002.

 

Water. We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line facilities are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The Riverton and State Line Power Plants’ National Pollution Discharge Elimination System Permits were issued in 2001.

 

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 steam leaks. We have been issued permits for Asbury, State Line and the Energy Center Power Plants. The Riverton Plant has not been issued an operating permit at this time. The State of Kansas requested that we draft the Title V Permit and submit it to the state. The permit has been drafted and submitted. We expect this permit will be issued during 2003.

 

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143) establishing standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible

 

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long-lived assets. We adopted FAS 143 on January 1, 2003, and as a result, have identified a liability for future containment of an ash landfill at the Riverton Power Plant. The potential cost of this future liability has been estimated as of the settlement date and has been discounted using a credit adjusted risk free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to this liability could occur due to changes in cost estimates, anticipated timing of settlement or federal or state regulatory requirements. We estimate the cost of this future containment project to be approximately $330,000.

 

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, 2002, would permit us to issue approximately $187.2 million of new first mortgage bonds (at an assumed interest rate of 7.0%) based on this test. The Mortgage provides an exception from this earnings requirement in certain instances relating to the issuance of new first mortgage bonds against first mortgage bonds which have been, or are to be, retired. 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, 2002, we had retired bonds and net property additions which would enable the issuance of at least $313.0 million principal amount of bonds if the annual interest requirements are met.

 

Under the Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in the 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 redeemed all of our outstanding preferred stock on August 2, 1999. Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.

 

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 or furnished electronically with the SEC. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.

 

ITEM 2. PROPERTIES

 

Electric Facilities

At December 31, 2002, we owned generating facilities with an aggregate generating capacity of 1004 megawatts.

 

Our principal electric baseload generating plant is the Asbury Plant with 213 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 21% of our owned generating capacity and in 2002 accounted for approximately 39% of the energy generated by us. Routine plant maintenance, during which the entire Plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring. Every fifth year the spring 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 Unit No. 2

 

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turbine is inspected approximately every 35,000 hours of operations and was also inspected during the last outage. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel costs associated with replacement energy.

 

Our generating plant located at Riverton, Kansas, has two steam-electric generating units with an aggregate generating capacity of 92 megawatts and three gas-fired combustion turbine units with an aggregate generating capacity of 44 megawatts. The steam-electric generating units burn coal as a primary fuel and have the capability of burning natural gas. Unit No. 8 was taken out of service on February 14, 2003 for its scheduled five-year maintenance outage as well as to make necessary repairs to a high-pressure cylinder. The outage is expected to last twelve weeks instead of the six weeks originally scheduled. The last five-year scheduled maintenance outage for the Riverton Plant’s other coal-fired unit, Unit No. 7, occurred in 2000.

 

We own a 12% undivided interest in the 670 megawatt coal-fired Unit No. 1 at the Iatan Generating Station located 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of the unit’s available capacity and are obligated to pay for that percentage of the operating costs of the unit. Kansas City Power & Light and Aquila own 70% and 18%, respectively, of the Unit. Kansas City Power & Light operates the unit for the joint owners. See Note 11 of “Notes to Financial Statements” under Item 8.

 

We also have two combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 169 megawatts. These peaking units operate on natural gas as well as oil. On October 25, 2001, we entered into an agreement to purchase two FT8 peaking units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. Both units have been delivered and are expected to be operational in the second quarter of 2003.

 

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 90 megawatts and a Combined Cycle Unit with generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines (including our former State Line Unit No. 2), two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc. which owns the remaining 40% of the unit. We are the operator of the Combined Cycle Unit. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the capability of burning oil.

 

Our hydroelectric generating plant, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts, subject to river flow. We are currently replacing the water wheels at our hydroelectric plant. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri.

 

At December 31, 2002, 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 6,387 miles of line.

 

Our electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common with Kansas City Power & Light and Aquila in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our property, plant and equipment are subject to the Mortgage.

 

Water Facilities

We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 83 miles of water mains in three communities in Missouri.

 

Other

We also have investments in non-regulated businesses which we commenced in 1996. We now lease capacity on our fiber optics network and provide Internet access, utility training, close-tolerance custom manufacturing, surge suppressors and other energy services through our wholly owned subsidiary, EDE Holdings, Inc. We created this subsidiary in 2001 to hold our non-regulated companies. EDE Holdings is a

 

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holding company which owns: a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business; a 100% interest in Conversant, Inc., a software company which markets the Internet-based customer information system software formerly named Centurion that was developed by Empire employees; a 100% interest in Southwest Energy Training that offers technical training to the utility industry; a 100% interest in Transaeris, a wireless Internet provider and a controlling 50.01 % interest in Mid-America Precision Products, 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. On February 1, 2003 we purchased Joplin.com, a leading Internet service provider in the Joplin, Missouri area. The purchase was made through Transaeris. We are merging Transaeris and Joplin.com into one company named Fast Freedom, Inc. We sold E-Watch, our electronic monitored security company, to Federal Protection, Inc. of Springfield, Missouri in December 2002 after it did not meet our earnings expectations.

 

ITEM 3. LEGAL PROCEEDINGS

 

See description of legal matters set forth in Note 12 of “Notes to Financial Statements” under Item 8, which description is incorporated herein by reference.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

None.

 

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PART II

 

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

 

Our common stock is listed on the New York Stock Exchange. On February 20, 2003, there were 6,482 record holders and 21,727 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 2002 and 2001 were as follows:

 

 

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock.

 

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, 2002, this dividend restriction did not affect any of our retained earnings.

 

Participants in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.

 

Our shareholders rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. See Note 6 of “Notes to Financial Statements” under Item 8 for additional information.

 

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 5 of “Notes to Financial Statements” under Item 8 for additional information regarding our common stock.

 

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ITEM 6. SELECTED FINANCIAL DATA

(Dollars in thousands, except per share amounts)

 

		2002			2001			2000			1999			1998
Operating revenues*		$	305,903		$	265,821		$	261,691		$	243,243		$	239,858
Operating income*		$	56,068		$	43,212		$	45,862		$	42,237		$	47,440
Total allowance for funds used during construction		$	571		$	3,611		$	5,775		$	1,193		$	409
Net income		$	25,524		$	10,403		$	23,617		$	22,170		$	28,323
Earnings applicable to common stock		$	25,524		$	10,403		$	23,617		$	19,463		$	25,912
Weighted average number of common shares outstanding		21,433,889			17,777,449			17,503,665			17,237,805			16,932,704
Basic and diluted earnings per weighted average shares outstanding		$	1.19		$	0.59		$	1.35		$	1.13		$	1.53
Cash dividends per common share		$	1.28		$	1.28		$	1.28		$	1.28		$	1.28
Common dividends paid as a percentage of earnings applicable to common stock		109.3		%	217.4		%	94.9		%	114.5		%	83.7		%
Allowance for funds used during construction as a percentage of earnings applicable to common stock		2.2		%	34.7		%	24.5		%	6.2		%	1.6		%
Book value per common share outstanding at end of year		$	14.28		$	13.64		$	13.62		$	13.44		$	13.40
Capitalization:
Common equity		$	329,315		$	268,308		$	240,153		$	234,188		$	229,791
Preferred stock without mandatory redemption provisions		$	0		$	0		$	0		$	0		$	32,634
Long-term debt		$	410,998		$	358,615		$	325,644		$	345,850		$	246,093
Ratio of earnings to fixed charges		2.25			1.36			2.25			2.70			3.32
Ratio of earnings to combined fixed charges and preferred stock dividend requirements		2.25			1.36			2.25			2.40			2.50
Total assets*		$	970,153		$	890,221		$	829,739		$	731,220		$	653,141
Plant in service at original cost*		$	1,125,460		$	1,080,100		$	928,561		$	878,287		$	838,883
Plant expenditures (inc. AFUDC)*		$	73,579		$	77,316		$	131,824		$	70,127		$	50,899

 

*Prior years have been reclassified to reflect non-utility property, revenues and expenses.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for 2002, compared to 2001, and for 2001, compared to 2000.

 

Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during 2002, approximately 41% were from residential customers, 29% from commercial customers, 16% from industrial customers, 4% from wholesale on-system customers, 5.5% from wholesale off-system transactions and 4.5% from miscellaneous sources such as transmission services and late payment fees. The percentage changes from the prior year in on-system kilowatt-hour (Kwh) sales and revenue by major electric customer class were as follows:

 

 

*Revenues excluding portion of the Interim Energy Charge that is refundable to customers. See discussion below.

 

On-System Transactions

Kwh sales for our on-system customers increased during 2002 primarily due to cooler temperatures in April and the fourth quarter (during our heating seasons) and warmer temperatures in June and September (during our air conditioning season) as compared to the same periods in 2001. Revenues for our on-system customers increased primarily as a result of the increased sales and the Missouri and Kansas rate increases discussed below. Our customer growth was 1.60% in 2002 and 1.13% in 2001. We expect our annual customer growth to be 1.4% over the next several years.

 

The increases in residential and commercial Kwh sales in 2002 were due primarily to the weather conditions discussed above. Industrial sales and revenues increased, reflecting increased sales in April 2002 and during August through November 2002 as compared to the same periods in 2001. Residential, commercial and industrial revenues for 2002 were also favorably impacted by the October 2001 Missouri rate increase and, to a lesser extent, the December 2002 Missouri rate increase and the July 2002 Kansas rate increase discussed below.

 

On-system wholesale Kwh sales increased reflecting the weather conditions discussed above. Revenues associated with these sales decreased in 2002 as compared to 2001 as a result of the operation of our fuel adjustment clause applicable to these FERC regulated sales.  This clause permits the pass through to customers of changes in fuel and purchased power costs, which are discussed further below.

 

Kwh sales and revenues for our on-system customers increased during 2001 as compared to 2000, primarily due to unseasonably cold temperatures in the first quarter of 2001 and warmer temperatures during the second quarter of 2001, offset by milder temperatures in the last two quarters of 2001. Residential and commercial Kwh sales and revenues increased compared to 2000 due to these weather conditions as well as increases in business activity throughout our service territory. Industrial Kwh sales for 2001 decreased due to a general slowdown in economic activity by the manufacturing sector in our service territory during the third and fourth quarters of 2001. Revenues in these classes were favorably impacted by the October 2001 Missouri rate increase.

 

On-system wholesale Kwh sales increased in 2001, reflecting the weather conditions discussed above. Revenues associated with these sales increased more than the corresponding Kwh sales as a result of the operation of our fuel adjustment clause applicable to these FERC regulated sales.

 

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Our future revenues from the sale of electricity will continue to be affected by economic conditions, weather, business activities, competition, fuel costs, changes in electric rate levels, customer growth and changes in patterns of electric energy use by customers and our ability to receive adequate and timely rate relief.

 

Rate Matters

The following table sets forth information regarding electric and water rate increases affecting the revenue comparisons discussed above:

 

 

On November 3, 2000, we filed a request with the Missouri Commission for a general annual increase in base rates for our Missouri electric customers in the amount of $41,467,926, or 19.36%. The Missouri Commission issued a final order on September 20, 2001 granting us an annual increase in rates of approximately $17.1 million, or 8.4%, effective October 2, 2001. In addition, the order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later. This IEC was collected subject to refund (with interest) at the end of the two year period to the extent money was collected from customers above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates.

 

On March 8, 2002, we filed a request with the Missouri Commission for an annual increase in base rates for our Missouri electric customers in the amount of $19,779,916 and also asked to have the IEC put into effect in the last rate case reconfigured to reflect a decrease of $9,994,888 in the amount to be billed to customers. The reconfigured IEC would remain subject to refund with interest. This request sought to recover new operating costs and obligations and reflect the changes in our capital structure since the rate increase in October 2001. Also on March 8, 2002, we filed an interim rate case for an annual increase in base rates of $3,562,983, the amount that was erroneously omitted from the increase granted in our 2001 rate case. The Missouri Commission rejected the interim request. After extensive negotiations with the Missouri Commission staff, Office of Public Counsel and other intervening parties, we filed a Unanimous Stipulation and Agreement Regarding “Error” in the 2001 rate case and an Immediate Reduction of the IEC with the Missouri Commission on May 14, 2002. This agreement was approved by the Missouri Commission on June 4, 2002 and provided for a $7 million annual reduction in the IEC.

 

On October 29, 2002, we filed a Unanimous Stipulation and Agreement, agreed to by the Missouri Commission staff, Office of Public Counsel and other intervening parties, with the Missouri Commission. This Agreement was approved by the Missouri Commission on November 22, 2002 and settled all matters covered by our March 2002 filings, provided us with an annual increase in rates of approximately $11.0 million, or 4.97%, effective December 1, 2002 and eliminated the IEC as of that date. The Agreement also calls for us to refund all funds collected under the IEC, with interest, by March 15, 2003.

 

At December 31, 2002, we had recorded a current liability of approximately $18.7 million for such rate refunds. We collected $2.8 million in 2001 and recorded $0.75 million as revenue. We collected $15.9 million in 2002 and recorded a revenue reduction of ($0.75) million associated with the revenue recognized in 2001 because it became certain that the entire amount of IEC revenues collected would be refunded. As a result, we have recognized no revenue in the aggregate for combined 2001 and 2002 associated with the IEC collections. The remainder of the funds collected in 2001 and 2002 were set aside as a provision for rate refunds and not recognized in operating revenue. As a result of the non-recognition of these funds, the refunds have already been reflected in our results (except for $0.3 million of interest) and will have no material impact on our earnings in 2003. The Agreement also provided for a change to the summer/winter rate differential for our residential customers with the new rates reflecting a smaller differential between summer and winter rates for usage above 600 kilowatt hours. Each of the parties to the Agreement also agreed not to file a new request

 

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for a general rate increase or decrease before September 1, 2003, barring any unforeseen, extraordinary occurrences.

 

On May 15, 2002, we filed a request with the Missouri Commission for an annual increase in base rates for our Missouri water customers in the amount of approximately $361,000, or 33.9%. This was the first requested increase in rates for our water customers since 1994. On November 7, 2002, we filed an Agreement Regarding Disposition of a Small Company Rate Increase Request, agreed to by the Commission staff, with the Missouri Commission. This agreement was approved by the Missouri Commission effective December 23, 2002 and provides us with an annual increase in rates of approximately $358,000, or 33.7%.

 

On December 28, 2001, we filed a request with the Kansas Corporation Commission (KCC) for an annual increase in base rates for our Kansas electric customers in the amount of $3,239,744, or 22.81%. This request sought to recover costs associated with our investment in State Line Unit No. 1, State Line Unit No. 2 and the State Line Combined Cycle Unit (SLCC), as well as significant additions to our transmission and distribution systems and operating cost increases which had occurred since our last rate increase in September 1994. We also requested reinstatement of a fuel adjustment clause for our Kansas rates. We filed a Unanimous Stipulation and Agreement, agreed to by the KCC staff and all intervening parties, with the KCC on June 7, 2002. The agreement stipulates that we will not file for general rate relief before November 1, 2003 barring any unforeseen, extraordinary occurrences. This agreement was approved by the KCC on June 27, 2002 providing us an annual increase in rates of approximately $2,539,000, or 17.87%, effective July 1, 2002. It did not provide for the reinstatement of a fuel adjustment clause.

 

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%.

 

We are currently discussing an increase in rates with our on-system wholesale electric customers, and will make a FERC rate filing in 2003.

 

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 Transactions

In addition to sales to our own customers, we sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers. During 2002 revenues from such off-system transactions were approximately $25.4 million as compared to approximately $7.5 million in 2001 and approximately $10.6 million during 2000. The increase in revenues during 2002 resulted primarily from the availability of competitively priced power from our SLCC which was placed in service in June 2001 and term purchases of firm energy during 2002 which, when not required to meet our own customers’ needs, could be sold in the wholesale market. Revenues for 2001 were less than for 2000 primarily because of our peak hour market-based rates being substantially lower during the summer months of 2001 than in 2000 and milder regional weather conditions in the fourth quarter of 2001 affecting demand. See “- Competition” below.

 

Operating Revenue Deductions

During 2002, total operating expenses increased approximately $11.8 million (7.4%) compared to the prior year. Total purchased power costs increased by approximately $0.4 million (0.6%) during 2002 although the amount of power purchased increased 20%, reflecting increased demand in the second and third quarters of 2002 and the term purchases of firm energy previously discussed. Purchased power costs reflected lower purchased power prices in 2002 than in 2001. Total fuel costs decreased approximately $5.5 million (9.8%) during 2002 as compared to 2001 primarily reflecting lower natural gas prices in 2002 as well as less generation by our gas-fired units due in large part to the term purchases of firm energy. Natural gas costs (on a per MMBtu basis) were lower by 30.5% during 2002 than in 2001. This is a result of a combination of lower commodity prices during 2002 and our natural gas procurement program.

 

Expenses relating to the proposed merger with Aquila, Inc., formerly UtiliCorp United Inc. (which was terminated by UtiliCorp on January 2, 2001) were $1.5 million during 2002 as compared to $1.4 million in 2001. Expenses related to the terminated merger in both 2002 and 2001 were primarily the result of expenses related to severance benefits incurred under our Change in Control Severance Pay Plan in the first quarters of those years. See Note 2 to “Notes to Financial Statements” for more information on the terminated merger. Other operating expenses increased approximately $6.3 million (17.3%) during 2002 primarily due to

 

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increases of $3.9 million in administrative and general expense resulting from increased expense for employee health care and benefit plans and decreased pension income, $1.4 million in transmission expense for the delivery of purchased energy to our system and $1.1 million in other power operation expenses related to a full year of operation of the SLCC. We anticipate significantly lower pension income in 2003. Expense related to our non-regulated businesses increased approximately $10.4 million during 2002 as compared to 2001. See “- Non-regulated Items” below for more information. Maintenance and repairs expense increased approximately $5.3 million (27.8%) during 2002. Expenditures under long-term maintenance contracts that serve to levelize maintenance costs over time and are reflected in our rates that became effective in October 2001, accounted for $4.5 million of this increase of which $2.9 million was for the maintenance contracts that began in January 2002 for the Energy Center and State Line Unit No. 1 and $1.6 million was for the first full year of these contracts for the SLCC, which commenced operations in June 2001. Maintenance costs associated with a three-week outage to replace the main transformer at the Asbury Plant during the second quarter of 2002 also contributed to this increase.

 

Depreciation and amortization expense decreased approximately $3.8 million (12.7%) during 2002 due to lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October 2001 Missouri rate order. Total provision for income taxes increased approximately $11.4 million (732.9%) during 2002 due primarily to higher taxable income and the benefit created by the deductibility of approximately $6.1 million in merger related expenses in the first quarter of 2001 as a result of the termination of the proposed merger with Aquila, Inc. in January 2001. See Note 10 of “Notes to Financial Statements” under Item 8 for additional information regarding income taxes. Other taxes increased approximately $2.6 million (19.0%) during 2002 as compared to 2001 primarily due to a reduction in capitalized property taxes related to the SLCC being placed in service in June 2001.

 

During 2001, total operating expenses increased approximately $10.0 million (6.8%) compared to the prior year. Total purchased power costs decreased by approximately $2.9 million (4.4%) during 2001 reflecting both the decreased demand in the third and fourth quarters resulting from milder temperatures and the increased generating capability due to the completion of the SLCC. Total fuel costs were up approximately $7.6 million (15.6%) during 2001 as compared to 2000 primarily reflecting the higher cost of natural gas, increased generation from the SLCC in the third and fourth quarters and less coal generation due to our Asbury Plant being out of service for scheduled and unscheduled repairs and maintenance during 13 weeks late in the year. Natural gas prices (on a per MMBtu basis) were higher by 35.9% during 2001 as compared to 2000.

 

Merger related expenses were $1.4 million during 2001 as compared to $0.3 million in 2000. Other operating expenses increased approximately $4.2 million (12.8%) during 2001 primarily due to an actuarially determined adjustment to our fully-funded pension benefit expense in the first quarter of 2001, decreased income of approximately $2.5 million from the pension fund caused by a decline in the value of invested funds during 2001 and additions to the bad debt reserve of approximately $0.7 million during 2001. Maintenance and repairs expense increased approximately $4.3 million (29.1%) during 2001 primarily due to initial operation of the SLCC and subsequent payments under our long-term maintenance contracts entered into in July 2001 for the SLCC combustion turbines.

 

Depreciation and amortization expense increased approximately $1.7 million (6.0%) during 2001 due to increased levels of plant and equipment placed in service. This increase was partially offset by lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October Missouri rate order. Total provision for income taxes decreased approximately $9.7 million (85.3%) during 2001 due primarily to lower taxable income and by the deductibility in 2001 of approximately $6.1 million in merger related expenses discussed above. Other taxes increased approximately $0.4 million (3.4%) during the year.

 

Non-regulated Items

In 2002, we began recording revenue from our non-regulated business in “Non-regulated” under Operating Revenues and including expense from such business in “Non-regulated” under the Operating Revenue Deductions section of our income statements rather than netting them under “Other - net” in the Other Income and Deductions section, as we had done in prior periods. We have reclassified the non-regulated revenues and expenses for prior periods to conform to the new presentations. Prior period amounts reclassified are not material to the results of operations for those periods. During 2002, total non-regulated operating revenue increased approximately $8.7 million while total non-regulated operating expense

 

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increased approximately $10.4 million compared with 2001. The increase in both revenues and expenses was primarily due to the consolidation of the financial statements of Mid-America Precision Products, LLC (MAPP), which was acquired in July 2002. MAPP specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, including components for specialized batteries for Eagle Picher Technologies. The increase in expense was also due to the activities of our wholly owned subsidiary, Conversant, Inc., a software company that began business in early 2002. Conversant markets the Internet-based customer information system software formerly named Centurion that was developed by Empire employees. In December 2002, we sold our monitored security business, E-Watch, to Federal Protection, Inc. of Springfield, Missouri after it did not meet our earnings expectations. This sale did not have a material effect on our financial position, results of operations or cash flows. On February 1, 2003 we purchased Joplin.com, a leading Internet service provider in the Joplin, Missouri area. The purchase was made through Transaeris, a non-regulated subsidiary of EDE Holdings, Inc. We are merging Transaeris and Joplin.com into one company named Fast Freedom, Inc. We began investing in non-regulated businesses in 1996 and now lease capacity on our fiber optics network and provide Internet access, utility industry technical training, close-tolerance custom manufacturing, surge suppressors and other energy services through our wholly owned subsidiary, EDE Holdings, Inc. See Item 1, “Business - General” for further information about these non-regulated businesses.

 

Nonoperating Items

Total allowance for funds used during construction (AFUDC) decreased $3.0 million in 2002 and $2.2 million in 2001 reflecting the completion of the SLCC in June 2001. See Note 1 of  “Notes to Financial Statements” under Item 8.

 

Other-net deductions decreased $1.5 million (145.8%) during 2002 primarily reflecting a $1.2 million unrealized gain on derivatives in December 2002 as compared to a $0.4 million loss in the second and third quarters of 2001. This loss was caused by the marking to market, required by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” of option contracts entered into in connection with our hedging activities that did not qualify for hedge accounting. The $1.2 million unrealized gain on derivatives resulted from anticipated natural gas usage that was financially hedged but no longer necessary because we were able to purchase power in the wholesale market more economically than generating it ourselves. As a result of our use of derivatives to manage our gas commodity risk and our exposure to gas and purchased power cost volatility (including hedging) and the use of mark-to-market accounting, revenues and earnings may fluctuate. Although our purpose is to minimize our risk from volatile natural gas prices and protect earnings, 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.

 

A one-time write-down of $4.1 million was taken in the third quarter of 2001 for disallowed capital costs related to the construction of the SLCC. These costs were disallowed as part of the stipulated agreement approved by the Missouri Commission in connection with our 2001 rate case and will not be recovered in rates. The net effect on 2001 earnings after considering the tax effect on this write-down was $2.5 million.

 

Total interest charges on long-term debt decreased $1.4 million (5.4%) in 2002 as compared to 2001 mainly due to the maturing of $37.5 million of our first mortgage bonds in July 2002. Total interest charges on long-term debt were virtually the same for 2001 as for 2000. Commercial paper interest decreased $1.5 million (68.0%) during 2002 reflecting decreased usage of short-term debt as well as lower interest rates. Interest related to our Trust Preferred Securities issued on March 1, 2001 increased $0.7 million (20.0%) during 2002 reflecting twelve months of interest as compared to the ten months in 2001. Interest income decreased $0.1 million (56.2%), reflecting the lower interest rates.

 

Other Comprehensive Income

The change in the fair market value of open contracts related to our gas procurement program and the amount of the contracts settled during the period being reported, including the tax effect of these items, are included in our Consolidated Statement of Comprehensive Income as the net change in unrealized gain or loss. This net change is recorded in Accumulated Other Comprehensive Income in the capitalization section of our balance sheet and does not affect earnings per share. The unrealized gains and losses accumulated in comprehensive income are reclassified to fuel expense in the periods in which they are actually realized. We

 

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had a net change in unrealized gain/(loss) of $8.2 million at the end of 2002 as compared to a net change of $(1.6) million at the end of 2001, the first year we recorded such contracts.

 

Earnings

Basic and diluted earnings per weighted average share of common stock were $1.19 during 2002 compared to $0.59 in 2001. This increase in earnings per share was primarily due to the October 2001 and December 2002 Missouri rate increases, the July 2002 Kansas rate increase, lower fuel and purchased power prices, an increase in off-system sales and decreased depreciation expense. Also favorably impacting 2002 earnings were cooler temperatures in April and the fourth quarter and warmer temperatures in June and September as compared to the same periods in 2001 and the $1.2 million unrealized gain on derivatives in December 2002. Earnings per share for 2002 were negatively impacted by $1.5 million in merger-related expenses as well as planned increased maintenance costs for our combustion turbine and combined cycle units. Excluding the $1.5 million in merger-related expenses and related taxes, earnings per share would have been $1.24 during 2002. Earnings for 2001 included approximately $2.3 million, after taxes, resulting from the tax benefit occurring because we recognized approximately $6.1 million of merger-related expenses upon the termination of the proposed merger with Aquila, Inc. in January 2001. Excluding $1.4 million in merger costs ($1.0 million net of taxes) for 2001, $2.5 million, net of related income taxes, from the write-down of the State Line construction expenditures and the one-time tax benefit, earnings per share would have been $0.66 in 2001. The calculation of our earnings per share for 2002 also gives effect to the sale in underwritten public offerings of 2.0 million shares of our common stock in December 2001 and 2.5 million shares in May 2002. See “- Liquidity and Capital Resources” below.

 

Basic and diluted earnings per weighted average share of common stock were $0.59 during 2001 compared to $1.35 in 2000. Earnings per share for 2001 were negatively impacted by the mild weather in the third and fourth quarters, increased natural gas prices and greater use of gas than in the prior year and the one-time non-cash charge of $2.5 million, net of related income taxes, from the write-down of the SLCC construction expenditures. Positively impacting earnings in 2001 was the one-time tax benefit of approximately $2.3 million from previously incurred merger-related costs and favorable weather conditions in the first and second quarters of 2001.

 

Our actual net income and basic and diluted earnings per share are determined in accordance with generally accepted accounting principles (GAAP). The earnings per share amounts described above that exclude merger expenses, the one-time tax benefit and the write-down of construction expenditures (and the corresponding adjusted net income amounts) are non-GAAP measures.  These non-GAAP measures are presented because we believe they provide a more accurate picture of our underlying financial performance. The following table provides a reconciliation of the differences between net income and basic and diluted earnings per share, as determined in accordance with GAAP, and these non-GAAP measures:

 

		Twelve Months Ended December 31,
		2002			2001				2000
Net income		$	25,524,000		$	10,403,000			$	23,617,000
Merger expenses (net of income taxes for 2001 and 2002)		1,002,000			1,081,000				327,000
Net loss from State Line Combined Cycle Plant disallowance		—			2,530,000				—
Tax benefit from merger expenses		—			(2,324,000			)	—
Net income (excluding merger expenses, disallowance and tax benefit)		$	26,526,000		$	11,690,000			$	23,944,000
Weighted average common shares outstanding		21,433,889			17,777,449				17,503,665
Basic and diluted earnings per share		$	1.19		$	0.59			$	1.35
Merger expenses per share (net of income taxes)		$	0.05		$	0.06			$	0.02
Net loss per share from State Line Combined Cycle Plant disallowance		$	—		$	0.14			$	—
Tax benefit per share from merger expenses		$	—		$		(0.13	)	$	—
Basic and diluted earnings per share (excluding merger expenses, disallowance and tax benefit)		$	1.24		$	0.66			$	1.37

 

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Competition

Federal regulation has promoted and is expected to continue to promote competition in the electric utility industry. However, none of the states in our service territory has legislation that could require competitive pricing to be put into effect.               The Arkansas Legislature passed a bill in April 1999 that called for deregulation of the state’s electricity industry as early as January 2002. However, a law was passed in February 2003 repealing deregulation in the state of Arkansas.

 

We, and all other electric utilities with interstate transmission facilities, operate under FERC regulated open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council. 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 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.  Since we are a transmission provider for our zone and are currently the only transmission customer taking service from that zone, we are currently being assessed 100 per cent of the zonal costs and receiving it back as revenue. To the extent that we are incurring these revenues and charges to serve our on-system wholesale and retail power customers, the associated costs are netted against the revenues collected and only the difference, if any, is recorded. In 2002, these total transmission costs and the associated revenues were approximately $4.7 million. In the event that other transmission customers take Network Integration Transmission Service in our zone, the revenues received will be reflected in electric operating revenues and the related charges will be expensed.

 

In December 1999, the FERC issued Order No. 2000 which encourages the development of RTOs.  RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power. After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and Midwest Independent Transmission System Operator, Inc. (MISO) agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was completed in February 2002. MISO filed the necessary documents with the FERC on March 29, 2002 and the consolidation is still in progress. This new organization would operate our system as part of an interconnected transmission system encompassing over 120,000 megawatts of generation capacity located in 20 states. MISO would collect revenues attributable to the use of each member’s transmission system and each member would be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. MISO and SPP filed a combined tariff for the new resulting company on November 1, 2002 as directed by the FERC. This new tariff would eliminate rate pancaking for transactions that occur between MISO and SPP customers, preserve the zonal rate structure under the current MISO and SPP tariffs, preserve the existing rates for certain long-term firm SPP service agreements, preserve the grandfathered contract provisions under both organizations’ tariffs and continue the stated rates currently on file under the SPP tariff. The FERC conditionally accepted the filing on December 19, 2002. We have filed with the FERC and the utility commissions in the four states in which we operate to transfer control over the operation of our transmission facilities to MISO. The Kansas Corporation Commission and the FERC have approved our requests while the filings in Missouri and Arkansas are still pending. Although we were not required to file in Oklahoma, we did a courtesy filing for informational purposes. If, however, the consolidation does not occur, we may operate our transmission separately while continuing to search for an RTO to join. We are unable to quantify the potential impact of either joining or not joining an RTO on our future financial position, results of operation or cash flows.

 

Approximately 4% 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. Our two largest wholesale customers accounted for 87% of our wholesale business in 2002. We have contracts with these customers that run through the first quarter of 2008.

 

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LIQUIDITY AND CAPITAL RESOURCES

 

Our construction-related expenditures, including AFUDC, totaled approximately $73.7 million, $71.8 million, and $133.9 million in 2002, 2001 and 2000, respectively.

 

A breakdown of these construction expenditures for 2002 is as follows:

 

 

Approximately 63% of construction expenditures for 2002 were satisfied internally from operations. The other 37% of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and unsecured Senior Notes discussed below.

 

We estimate that our construction expenditures, including AFUDC, will total approximately $50.2 million in 2003, $31.2 million in 2004 and $32.6 million in 2005. Of these amounts, we anticipate that we will spend $13.8 million, $15.7 million and $18.0 million in 2003, 2004 and 2005, respectively, for additions to our distribution system to meet projected increases in customer demand. These construction expenditure estimates also include approximately $22.0 million in 2003 for two FT8 peaking units at the Empire Energy Center. In October 2001, we entered into an agreement to purchase these two FT8 peaking units, each having generating capacity of 50 megawatts. Both units have been delivered and are scheduled to be operational in the second quarter of 2003. We estimate that the cost of both of these units will be approximately $55.0 million, excluding AFUDC.

 

Our net cash flows provided by operating activities increased $40.6 million during 2002 as compared to 2001 due mainly to a $15.1 million increase in net income and a $13.0 million increase in the amount of the IEC collected from Missouri electric customers. The refund of this IEC (which totals $18.7 million) during the first quarter of 2003 will have a material impact on our cash flows for the quarter although it will not have a material impact on earnings per share due to the non-recognition of these funds as operating revenue.

 

Our net cash flows used in investing activities decreased $1.9 million during 2002 as compared to 2001 because of decreased construction expenditures due mainly to the completion of the SLCC in June 2001.

 

Our net cash flows provided by financing activities decreased $48.5 million during 2002 as compared to 2001 mainly due to the repayment of $37.5 million of our First Mortgage Bonds due July 1, 2002 and the repayment of $33.0 million of short-term debt in 2002 as compared to $14.0 million in 2001. We sold common stock in May 2002 and December 2001, Senior Notes in December 2002 and Trust Preferred Securities in March 2001 as described below. The proceeds from such sales in 2002 totaled $12.3 million more than the proceeds from the 2001 sales.

 

We estimate that internally generated funds will provide at least 63% of the funds required in 2003 for construction expenditures. As in the past, we intend to utilize short-term debt to finance the additional amounts needed for such construction and repay such borrowings with the proceeds of sales of long-term debt or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) and internally generated funds. We will continue to utilize short-term debt as needed to support normal operations or other temporary

 

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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.

 

On March 1, 2001, we sold two million of 8 1/2% Trust Preferred Securities in a public underwritten offering. This sale generated proceeds of $50.0 million and issuance costs of $1.8 million. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8 1/2% of the $25 liquidation amount. Quarterly payments of dividends by the trust which issued the securities, as well as payments of principal, are made from cash received from corresponding payments made by us on $50.0 million aggregate principal amount of our 8.5% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust, and held by the trust as assets. Our interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The net proceeds of this offering were added to our general funds and were used to repay short-term indebtedness.

 

On December 10, 2001, we sold to the public in an underwritten offering 2,012,500 newly issued shares of our common stock for $41.0 million. The net proceeds of approximately $39.0 million from the sale were added to our general funds and used to repay short-term debt.

 

On May 7, 2002 we entered into a 370-Day $100,000,000 unsecured revolving credit facility. This credit facility replaced all of our existing lines of credit. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include the Trust Preferred Securities) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes distributions on the Trust Preferred Securities) 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. This credit facility is also subject to cross-default with our other indebtedness (in excess of $5,000,000 in the aggregate). There are no borrowings outstanding under this revolver as of December 31, 2002. However, $23 million of the facility as of that date was used to back up our commercial paper and was not available to be borrowed. See Note 8 of “Notes to Financial Statements” regarding our lines of credit.

 

On May 22, 2002, we sold to the public in an underwritten offering 2,500,000 shares of newly issued common stock for $51.9 million. The net proceeds of approximately $49.4 million were used to repay $37.5 million of our First Mortgage Bonds, 7.50% Series due July 1, 2002 and to repay short-term debt.

 

On July 17, 2002 our subsidiary, EDE Holdings, Inc., together with other investors, acquired the assets of the Precision Products Department of Eagle Picher Technologies, LLC. The acquisition was accomplished through the creation of a newly formed limited liability company, Mid-America Precision Products, LLC (MAPP). EDE Holdings, Inc. acquired a controlling 50.01 percent interest in MAPP through a cash investment of $0.65 million and is the guarantor for 50.01% of a $2.7 million long-term note payable and a $0.5 million revolving short-term credit facility.

 

On December 23, 2002, we sold to the public in an underwritten offering $50 million of our unsecured 7.05% Senior Notes which mature on December 15, 2022. The net proceeds of approximately $48.6 million were added to our general funds and used to repay short-term debt.

 

We have an effective shelf registration under which approximately $100 million of common stock and unsecured debt securities remain available for issuance.

 

On December 24, 2002, we received approval from the Kansas Corporation Commission for the issuance of an additional 100,000 shares of our common stock for our Director’s Stock Unit Plan and an additional 200,000 shares of our common stock for our 401(k) Plan and ESOP.

 

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, 2002 would permit us to issue approximately $187.2 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%. The Mortgage provides an exception from this earnings requirement in certain instances, relating to the issuance of new first mortgage bonds against first mortgage bonds which have been, or are to be, retired. We have no plans to issue any first mortgage bonds. See Note 7 to “Notes to Financial Statements” for more information on the mortgage bond indenture.

 

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Moody’s Investors Service currently rates our first mortgage bonds (other than the pollution control bonds) Baa1 and our senior unsecured debt Baa2. Standard & Poor’s downgraded our first mortgage bonds (other than the pollution control bonds) on July 2, 2002 from A- to BBB, our senior unsecured debt from BBB+ to BBB- and our Trust Preferred Securities from BBB to BB+. Standard & Poor’s outlook, however, was revised from negative to stable. In July 2001, Moody’s adjusted the credit rating of our Trust Preferred Securities from Baa1 to Baa3 due to technical changes in Moody’s methodology for rating this classification of security.

As of December 31, 2002, the ratings for our securities were as follows:

 

 

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 the cost of the securities when they are sold. Ratings below investment grade (Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt as described above, commercial paper or other securities or make the marketing of such securities more difficult.

 

Contractual Obligations

Set forth below is information summarizing our contractual obligations as of December 31, 2002:

 

		Payments Due by Period (in millions)
Contractual Obligations		Total			Less than 1 Year			1-3 Years			3-5 Years			More than 5 Years
Long-Term Debt (w/o discount)		$	358.5		$	—		$	110.0		$	—		$	248.5
Trust Preferred Securities		50.0			—			—			—			50.0
Capital Lease Obligations		0.7			0.2			0.5			—			—
Operating Lease Obligations		—			—			—			—			—
Purchase Obligations*		265.5			50.0			96.4			51.2			67.9
Other Long-Term Obligations**		2.7			0.2			0.5			2.0			—
Total Contractual Obligations		$	677.4		$	50.4		$	207.4		$	53.2		$	366.4

 

*includes fuel and purchased power contracts, ( including a long-term coal contract signed February 21, 2003).

**Other Long-term Obligations represent 100% of the long-term debt issued by Mid-America Precision Products, LLC.  EDE Holdings, Inc. is  the 50.01% guarantor of a $2.6 million note included in this total amount..

 

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.

 

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Critical Accounting Policies

Set forth below are certain accounting policies that are considered by management to be critical and to possibly involve significant risk, which means that they typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

 

Pensions. Our pension expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years. Our policy is consistent with the provisions of SFAS 87, “Employers’ Accounting for Pensions.”

 

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 and discount rates.

 

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 policy is consistent with the provisions of SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

 

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, healthcare cost trend rates and discount 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 (under a set of predetermined percentages) that lock in prices in an attempt to lessen the volatility in our fuel expense and gain predictability, thus protecting earnings. 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 instruments are recognized as the fair value of the derivative instrument changes. Our policy is consistent with the provisions of SFAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, An Amendment of SFAS 133.”

 

As of February 17, 2003, 84% of our anticipated volume of natural gas usage for the remainder of year 2003 is hedged at an average price of $3.17 per Dekatherm (Dth). In addition, approximately 60% of our anticipated volume of natural gas usage for the year 2004 is hedged at an average price of $3.25 per Dth, and approximately 16% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $3.76 per Dth.

 

Risks and uncertainties affecting the application of this accounting policy include:  market conditions in the energy industry, especially the effects of price volatility on contractual commodity commitments, regulatory and political environments and requirements, fair value estimations on longer term contracts, estimating underlying fuel demand and counterparty ability to perform.

 

Regulatory Assets.  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.

 

As of December 31, 2002, we have recorded $36,169,683 in regulatory assets and $11,840,810 in income taxes as a regulatory liability. These amounts are being amortized over periods of up to 25 years. See Note 4 of “Notes to Financial Statements” under Item 8 for detailed information regarding our regulatory assets and liabilities.

 

27

 

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 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.

 

RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143).  This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. We adopted FAS 143 on January 1, 2003 and have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant in which we have a 12% ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant.

 

The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations.  These liabilities have been estimated as of the settlement date and have been discounted using a credit adjusted risk free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. Upon adoption of this statement, we recorded a non-recurring discounted liability of approximately $400,000 in the first quarter of 2003. There will be no material effect to the Consolidated Statement of Income.

 

In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, “ Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144), establishing new standards for accounting and reporting for the impairment or disposal of long-lived assets. This statement eliminates the requirement under SFAS 121 to allocate goodwill to long-lived assets to be tested for impairment. We adopted FAS 144 on January 1, 2002 and there was no impact of the adoption of this Statement on our financial condition and results of operations.

 

In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (FAS 145). This statement eliminates the requirement (in both FAS 4 and FAS 64) that gains and losses from the extinguishment of debt be aggregated and, if material, classified as an extraordinary item, net of the related income tax effect. Further, FAS 145 eliminates an inconsistency between the accounting for sale-leaseback transactions and certain lease modifications that have economic effects that are similar to sale-leaseback transactions. FAS 145 also makes several other technical corrections to existing pronouncements that may change accounting practice and is effective for transactions occurring after May 15, 2002. We do not believe that the adoption of this Statement will have a material impact on our financial condition and results of operations.

 

In June 2002, the Financial Accounting Standards Board issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” (FAS 146). FAS 146 addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the Emerging Issues Task Force has set forth. The scope of FAS 146 also includes costs related to terminating a contract that is not a capital lease and termination benefits that employees who are involuntarily terminated receive under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. FAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. We will continue to evaluate FAS 146 but do not believe that the adoption of this Statement will have a material impact on our financial condition and results of operations.

 

In December 2002, the Financial Accounting Standards Board issued SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure” (FAS 148).  FAS 148 amends SFAS No. 123,

 

28

 

“Accounting for Stock-Based Compensation” (FAS 123), to provide alternative methods of transition when an entity changes from the intrinsic value method to the fair-value method of accounting for stock-based employee compensation. FAS 148 amends the disclosure requirements of FAS 123 to require more prominent and more frequent disclosure about the effects of stock-based compensation by requiring pro forma data to be presented more prominently and in a more user-friendly format in the footnotes to the financial statements. In addition, FAS 148 requires that the information be included in interim as well as annual financial statements. The transition guidance and annual disclosure provisions of FAS 148 are effective for fiscal years ending after December 15, 2002. We have adopted the transition and disclosure provisions of FAS 148 and now recognize compensation expense related to stock option issuances on or subsequent to January 1, 2002 under the fair- value provisions of FAS 123.  We do not have any transition issues and, accordingly, we do not believe FAS 148 will have a material impact on our financial condition and results of operations.

 

In November 2002, the FASB issued FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and Interpretation of FASB Statements Nos. 5, 57, and 107 and recession of FASB Interpretation No. 34”.  FIN 45 requires: (1) the guarantor of debt to recognize a liability, at the inception of the guarantee, for the fair value of the obligation undertaken in issuing this guarantee, (2) indirect guarantees of debt to be recognized in the financial statements of the guarantor and (3) the guarantor to disclose the background and nature of the guarantee, the maximum potential amount to be paid under the guarantee, the carrying value of the liability associated with the guarantee and any recourse of the guarantor to recover amounts paid under the guarantee from third parties.  FIN 45 rescinds all the provisions of FIN 34, Disclosure of Indirect Guarantees of Indebtedness of Others; as it has been incorporated into the provisions of FIN 45.  The provisions of FIN 45 are effective for all guarantees issued or modified subsequent to December 31, 2002.  The disclosure requirements of FIN 45 are effective for the financial statements of interim and annual periods ending after December 15, 2002. We do not have any commitments within the scope of FIN 45.

 

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”.  The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities” or “VIEs”) and how to determine when and which business enterprise should consolidate the VIE (the “primary beneficiary”). This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures.  FIN 46 may require more enterprises to consolidate entities with which they have contractual, ownership, or other pecuniary interests that absorb a portion of that entity’s expected losses or receive a portion of the entity’s residual returns. We are not the primary beneficiary of any VIEs.

 

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. Wehandle market risk in accordance with established policies, which may include entering into various derivative transactions. During the second quarter of 2001, we began utilizing derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 14 of “Notes to Consolidated Financial Statements” for further information.

 

Interest Rate Risk. We are exposed to changes in interest rates as a result of significant financing through our issuance of commercial paper.  We manage our interest rate exposure by limiting our variable-rate exposure to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.  See Notes 7 and 8 of “Notes to Financial Statements” under Item 8 for further information.

 

29

 

If market interest rates average 1% more in 2003 than in 2002, our interest expense would increase, and income before taxes would decrease by approximately $226,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2002.  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.

 

30

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

 

Report of Independent Accountants

 

To the Board of Directors and Shareholders

of The Empire District Electric Company:

 

In our opinion, the consolidated financial statements listed in the index appearing under Item 15 on page 67 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 on page 67 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 the financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.  We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

 

 

PricewaterhouseCoopers LLP

St. Louis, Missouri

February 4, 2003

 

 

31

 

Consolidated Balance Sheets

 

		December 31,
		2002			2001
Assets
Plant, at original cost:
Electric		$	1,099,983,796		$	1,061,452,770
Water		8,400,720			7,810,754
Non-regulated		17,075,955			10,836,489
Construction work in progress		41,504,451			20,136,645
		1,166,964,922			1,100,236,658
Accumulated depreciation		372,892,648			349,743,785
		794,072,274			750,492,873
Current assets:
Cash and cash equivalents		14,439,227			11,440,275
Accounts receivable – trade, net of allowance of $679,000 and $895,000, respectively		21,993,819			19,621,889
Accrued unbilled revenues		9,543,729			10,986,746
Accounts receivable – other		9,979,840			7,231,772
Fuel, materials and supplies		31,227,447			20,094,559
Unrealized gain in fair value of derivative contracts		5,983,490			20,000
Prepaid expenses		1,640,745			1,063,195
		94,808,297			70,458,436
Noncurrent assets and deferred charges:
Regulatory assets		36,169,683			37,743,107
Unamortized debt issuance costs		6,287,639			5,180,243
Unrealized gain in fair value of derivative contracts		16,949,388			7,706,580
Other		21,866,142			18,639,293
		81,272,852			69,269,223
Total Assets		$	970,153,423		$	890,220,532

 

The accompanying notes are an integral part of these consolidated financial statements.

 

32

 

		December 31,
		2002			2001
Capitalization and Liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 22,567,179 and 19,759,598 shares issued and outstanding, respectively		$	22,567,179		$	19,759,598
Capital in excess of par value		260,559,197			208,223,200
Retained earnings		39,544,819			41,906,483
Accumulated other comprehensive income (loss), net of income tax		6,643,467			(1,581,310		)
Total common stockholders’ equity		329,314,662			268,307,971
Long-term debt:
Company obligated mandatorily redeemable trust preferred securities of subsidiary holding solely parent debentures		50,000,000			50,000,000
Obligations under capital lease		462,618			567,315
First mortgage bonds and secured debt		210,535,477			208,047,363
Unsecured debt		150,000,000			100,000,000
Total long-term debt		410,998,095			358,614,678
Total long-term debt and common stockholders’ equity		740,312,757			626,922,649
Current liabilities:
Current maturities of long-term debt		—			37,500,000
Obligations under capital lease		194,143			158,329
Commercial paper		22,541,000			55,500,000
Accounts payable and accrued liabilities		37,496,190			34,520,862
Customer deposits		4,644,105			4,127,061
Interest accrued		3,990,184			5,091,240
Provision for rate refund		18,718,679			2,843,444
Unrealized loss in fair value of derivative contracts		64,000			1,279,430
		87,648,301			141,020,366
Commitments and contingencies (Note 12)
Noncurrent liabilities and deferred credits:
Regulatory liability		11,840,810			12,915,456
Deferred income taxes		103,144,549			84,625,946
Unamortized investment tax credits		6,131,000			6,681,000
Postretirement benefits other than pensions		4,928,965			4,884,161
Unrealized loss in fair value of derivative contracts		10,914,668			8,994,450
Minority Interest		806,319			—
Other		4,426,054			4,176,504
		142,192,365			122,277,517
Total capitalization and liabilities		$	970,153,423		$	890,220,532

 

The accompanying notes are an integral part of these consolidated financial statements.

 

33

 

Consolidated Statements of Income

 

		Year ended December 31,
		2002			2001			2000
Operating revenues:
Electric		$	294,571,794		$	263,189,506		$	258,937,329
Water		1,075,671			1,065,348			1,066,129
Non-Regulated		10,255,530			1,566,028			1,687,469
		305,902,995			265,820,882			261,690,927
Operating revenue deductions:
Operating expenses:
Fuel		50,994,406			56,523,370			48,899,577
Purchased power		62,765,107			62,383,952			65,238,096
Non-Regulated		11,911,021			1,478,978			1,408,524
Expenses related to terminated merger		1,524,355			1,391,673			327,397
Other		43,064,291			36,726,181			32,570,495
		170,259,180			158,504,154			148,444,089
Maintenance and repairs		24,395,974			19,094,735			14,795,210
Depreciation and amortization		26,084,430			29,868,851			28,106,919
Provision for income taxes		12,920,001			1,551,165			11,475,586
Other taxes		16,175,446			13,590,023			13,006,942
		249,835,031			222,608,928			215,828,746
Operating income		56,067,964			43,211,954			45,862,181
Other income and (deductions):
Allowance for equity funds used during construction		—			569,961			2,373,710
Interest income		87,336			199,447			641,602
Loss on plant disallowance		—			(4,087,066		)	—
Provision for other income taxes		(390,000		)	1,551,165			(149,414		)
Minority interest		(142,463		)	—			—
Other – net		472,387			(1,032,085		)	(471,037		)
		27,260			(2,798,578		)	2,394,861
Income before interest charges		56,095,224			40,413,376			48,257,042

 

The accompanying notes are an integral part of these consolidated financial statements.

 

34

 

		Year ended December 31,
		2002			2001			2000
Income before interest charges		$	56,095,224		$	40,413,376		$	48,257,042
Interest charges:
Trust preferred distributions by subsidiary holding solely parent debentures		4,250,000			3,541,667			—
Other long-term debt		24,957,961			26,384,310			26,355,901
Allowance for borrowed funds used during construction		(570,808		)	(3,041,298		)	(3,401,325		)
Other		1,933,953			3,125,783			1,685,312
		30,571,106			30,010,462			24,639,888
Net income		$	25,524,118		$	10,402,914		$	23,617,154
Weighted average number of common shares outstanding		21,433,889			17,777,449			17,503,665
Basic and diluted earnings per weighted average share of common stock		$	1.19		$	0.59		$	1.35
Dividends per share of common stock		$	1.28		$	1.28		$	1.28

 

The accompanying notes are an integral part of these consolidated financial statements.

 

35

 

Consolidated Statements of Comprehensive Income

 

		Year ended December 31,
		2002			2001			2000
Net income		$	25,524,118		$	10,402,914		$	23,617,154
Derivative contracts settled		337,660			690,400			—
Change in fair value of open derivative contracts for period		12,928,110			(3,240,900		)	—
Income taxes		(5,040,993		)	969,190			—
Net change in unrealized gain/(loss) on derivative contracts		8,224,777			(1,581,310		)	—
Comprehensive income		$	33,748,895		$	8,821,604		$	23,617,154

 

The accompanying notes are an integral part of these consolidated financial statements.

 

36

 

Consolidated Statements of Common Stockholders’ Equity

 

		Year ended December 31,
		2002			2001			2000
Common stock, $1 par value:
Balance, beginning of year		$	19,759,598		$	17,596,530		$	17,369,855
Stock/stock units issued through:
Public offering		2,500,000			2,012,500			—
Stock purchase and reinvestment plans		307,581			150,568			226,675
Balance, end of year		$	22,567,179		$	19,759,598		$	17,596,530
Capital in excess of par value:
Balance, beginning of year		$	208,223,200		$	168,439,089		$	163,909,731
Excess of net proceeds over par value of stock issued:
Public offering		46,857,626			37,023,140			—
Stock purchase and reinvestment plans		5,478,371			2,760,971			4,529,358
Balance, end of year		$	260,559,197		$	208,223,200		$	168,439,089
Retained earnings:
Balance, beginning of year		$	41,906,483		$	54,117,292		$	52,908,432
Net income		25,524,118			10,402,914			23,617,154
		67,430,601			64,520,206			76,525,586
Less common stock dividends declared		27,885,782			22,613,723			22,408,294
Balance, end of year		$	39,544,819		$	41,906,483		$	54,117,292
Accumulated other comprehensive income (loss):
Balance, beginning of year		$	(1,581,310	)	$	—		$	—
Derivative contracts settled		337,660			690,400			—
Change in fair value of open derivative contracts for period		12,928,110			(3,240,900		)	—
Income taxes		(5,040,993		)	969,190			—
Balance, end of year		$	6,643,467		$	(1,581,310	)	$	—

 

The accompanying notes are an integral part of these consolidated financial statements.

 

37

 

Consolidated Statements of Cash Flows

 

		Year ended December 31,
		2002			2001			2000
Operating activities
Net income		$	25,524,118		$	10,402,914		$	23,617,154
Adjustments to reconcile net income to cash flows provided by operating activities:
Depreciation and amortization		29,301,526			32,855,222			31,354,048
Pension income		(3,581,781		)	(4,366,247		)	(7,780,497		)
Deferred income taxes, net		12,180,000			810,000			2,053,000
Investment tax credit, net		(550,000		)	(550,000		)	(580,000		)
Allowance for equity funds used during construction		—			(569,961		)	(2,373,710		)
Issuance of common stock and stock options for incentive plans		1,195,752			941,823			844,405
Loss on plant disallowance		—			4,087,066			—
Unrealized gain on ineffective derivative contracts		(1,238,940		)	—			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues		(2,668,531		)	(2,423,368		)	(4,652,024		)
Fuel, materials and supplies		(2,098,946		)	(5,505,306		)	1,389,537
Prepaid expenses and deferred charges		559,689			(831,109		)	(1,427,249		)
Accounts payable and accrued liabilities		1,686,387			(1,261,594		)	10,550,235
Customer deposits, interest and taxes accrued		(584,012		)	(1,796,926		)	2,302,180
Other liabilities and deferred credits		436,818			798,001			753,012
Accumulated provision for rate refunds		15,875,234			2,843,445			—
Net cash provided by operating activities		76,037,314			35,433,960			56,050,091

 

The accompanying notes are an integral part of these consolidated financial statements.

 

38

 

		Year ended December 31,
		2002			2001			2000
Investing activities
Construction and other expenditures		$	(72,805,389	)	$	(78,569,879	)	$	(132,076,082	)
Non-regulated construction and other		(4,071,514		)	(792,394		)	(1,857,845		)
Allowance for equity funds used during construction		—			569,961			2,373,710
Net cash used in investing activities		(76,876,903		)	(78,792,312		)	(131,560,217		)
Financing activities
Proceeds from issuance of senior notes		50,000,000			—			—
Proceeds from issuance of common stock		56,465,200			42,964,341			3,911,628
Proceeds from issuance of trust preferred securities		—			50,000,000			—
Long-term debt issuance costs		(1,574,401		)	(1,884,756		)	—
Common stock issuance costs		(2,517,374		)	(1,958,985		)	—
Dividends		(27,885,782		)	(22,613,723		)	(22,408,294		)
Repayment of long-term debt		(37,690,102		)	(198,830		)	(286,000		)
Net (repayments) proceeds from short-term borrowings		(32,959,000		)	(14,000,000		)	69,500,000
State Line advance payments		—			—			6,504,516
Net cash provided by financing activities		3,838,541			52,308,047			57,221,850
Net increase (decrease) in cash and cash equivalents		2,998,952			8,949,695			(18,288,276		)
Cash and cash equivalents, beginning of year		11,440,275			2,490,580			20,778,856
Cash and cash equivalents, end of year		$	14,439,227		$	11,440,275		$	2,490,580

 

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. Interest paid was $30,943,000, $31,705,000, and $26,485,000 for the years ended December 31, 2002, 2001, and 2000, respectively. Income taxes paid were $1,767,000, $4,343,000, and $8,801,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Capital lease obligations incurred for the purchase of equipment was $748,000 for the year ended December 31, 2001. There were no capital lease obligations incurred during the years ended December 31, 2002 and 2000.

 

The accompanying notes are an integral part of these consolidated financial statements.

 

39

 

Notes to Consolidated Financial Statements

 

1.             Summary of Accounting Policies

 

We are subject to regulation by the Missouri Public Service Commission (MoPSC), 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). 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 2002 were derived as follows: residential 41%, commercial 29%, industrial 16%, wholesale on-system 4%, wholesale off-system 5.5% and other 4.5%. Our electric revenues for 2002 by jurisdiction were as follows: Missouri 88%, Kansas 6%, Arkansas 3%, and Oklahoma 3%. Following is a description of the Company’s significant accounting policies:

 

Basis of Presentation

The consolidated financial statements include the accounts of The Empire District Electric Company (EDEC), and the consolidated financial statements of its wholly owned non-regulated subsidiary, EDE Holdings, Inc. (EDE Holdings). The consolidated entity is referred to throughout as “we” or the “Company”. Currently, the electric utility accounts for about 98% of consolidated assets and 97% of consolidated revenues. Through the non-regulated subsidiary, we lease capacity on our fiber optics network and provide Internet access, utility training, close- tolerance custom manufacturing, surge suppressors and other energy services. For discussion of the acquisition of certain non-regulated operations in 2002 see Note 3. See Non-Regulated Information later in this footnote for additional information regarding non-regulated results of operations.

 

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 us (the MoPSC, the KCC, the OCC, the APSC and the FERC).

 

Certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to customers. As such, we have recorded certain regulatory assets that 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.

 

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.

 

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

 

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date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Actual amounts could differ from those estimates.

 

Revenue Recognition

We use cycle billing and accrue estimated, but unbilled, revenue and also a liability for the related taxes at the end of each period.

 

Property and Plant

The costs of additions to property, plant 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). Maintenance expenditures and the renewal of items not considered units of property are charged to income as incurred. The cost of units retired is charged to accumulated depreciation, which is credited with salvage and charged with removal costs.

 

Depreciation

Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities and are applied to the various classes of assets on a composite basis. Such provisions approximated 2.6%, 3.0% and 3.2% of depreciable property for 2002, 2001 and 2000, respectively. Depreciation expense for the years ended December 31, 2002, 2001 and 2000 was $27,693,556, $31,448,830 and $29,663,792, respectively.

 

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 2.4% for 2002, 5.6% for 2001 and 8.4% for 2000 compounded semiannually in determining AFUDC.

 

Asset Impairments

We periodically review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that there is impairment, analysis is performed based on several criteria, including but not limited to revenue trends, discounted operating cash flows and other operating factors, to determine the impairment amount. In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144), establishing new standards for accounting and reporting for the impairment or disposal of long-

 

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lived assets. This statement eliminates the requirement under SFAS No. 121 to allocate goodwill to long lived assets to be tested for impairment. We adopted FAS 144 on January 1, 2002. We believe there is no impairment of long-lived assets at December 31, 2002.

 

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.

 

Franchise Taxes

Franchise taxes are collected for and remitted to their respective cities and are included in other taxes in the consolidated statement of income. Operating revenues also include franchise taxes of $5,464,000, $4,850,000 and $4,560,000 for each of the years ended December 31, 2002, 2001 and 2000, respectively.

 

Income Taxes

Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates.

 

Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate.

 

Computations of Earnings Per Share

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive restricted and subscribed shares. The weighted average number of common shares outstanding used to compute basic earnings per share for the 2002, 2001 and 2000 periods was 21,433,889, 17,777,449 and 17,503,665, respectively. Dilutive shares for the 2002, 2001 and 2000 periods were 3,821, 8,118 and 7,105, respectively. In 2002, 69,700 options to purchase shares of common stock, with an exercise price of $20.95, were excluded from the calculation of diluted earnings per share as the exercise price was greater than the average market price.

 

Stock-Based Compensation

At December 31, 2002, we had several stock-based compensation plans, which are described in more detail in Note 5. We apply the recognition and fair-value measurement principles of SFAS No. 123, “Accounting for Stock-Based Compensation” (FAS 123), for all stock option issuances on or subsequent to January 1, 2002 and APB 25 “Accounting for Stock Issued to Employees”, and related Interpretations for issuances prior to that date. If the fair-value based accounting

 

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method under FAS 123 had been used to account for stock-based compensation costs, the effects on 2001 and 2000 net income and earnings per share would have been immaterial.

 

Non-Regulated Information

As discussed earlier, the Consolidated Financial Statements include the accounts of our wholly owned non-regulated subsidiary, EDE Holdings, Inc. The table below presents information about the reported revenues, net income, total assets, and related minority interest of the non-regulated businesses of the Company.

 

 

Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143). This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. We adopted FAS 143 on January 1, 2003 and have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant in which we have a 12% ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant.

 

The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. These liabilities have been estimated as of the settlement date and have been discounted using a credit adjusted risk free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. Upon adoption of this statement, we recorded a non-recurring discounted liability of approximately $400,000 in the first quarter of 2003. There will be no material effect to the Consolidated Statement of Income.

 

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In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144), establishing new standards for accounting and reporting for the impairment or disposal of long-lived assets. This statement eliminates the requirement under FAS 121 to allocate goodwill to long-lived assets to be tested for impairment. We adopted FAS 144 on January 1, 2002 and there was no impact of the adoption of this Statement on our financial condition and results of operations.

 

In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, “Rescission of SFAS No. 4, 44, and 64, Amendment of SFAS No. 13, and Technical Corrections” (FAS 145). This statement eliminates the requirement (in both FAS 4 and FAS 64) that gains and losses from the extinguishment of debt be aggregated and, if material, classified as an extraordinary item, net of the related income tax effect. Further, FAS 145 eliminates an inconsistency between the accounting for sale-leaseback transactions and certain lease modifications that have economic effects that are similar to sale-leaseback transactions. FAS 145 also makes several other technical corrections to existing pronouncements that may change accounting practice and is effective for transactions occurring after May 15, 2002. We do not believe that the adoption of this Statement will have a material impact on our financial condition and results of operations.

 

In June 2002, the Financial Accounting Standards Board issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” (FAS 146). FAS 146 addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the Emerging Issues Task Force has set forth. The scope of FAS 146 also includes costs related to terminating a contract that is not a capital lease and termination benefits that employees who are involuntarily terminated receive under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. FAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. We will continue to evaluate FAS 146 but do not believe that the adoption of this Statement will have a material impact on our financial condition and results of operations.

 

In December 2002, the Financial Accounting Standards Board issued SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure” (FAS 148). FAS 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition when an entity changes from the intrinsic value method to the fair-value method of accounting for stock-based employee compensation. FAS 148 amends the disclosure requirements of FAS 123 to require more prominent and more frequent disclosure about the effects of stock-based compensation by requiring pro forma data to be presented more prominently and in a more user-friendly format in the footnotes to the financial statements. In addition, FAS 148 requires that the information be included in interim as well as annual financial statements. The transition guidance and annual disclosure provisions of FAS 148 are effective for fiscal years ending after December 15, 2002. We have adopted the transition and disclosure provisions of FAS 148 and now recognize compensation expense related to stock option issuances on or subsequent to January 1, 2002 under the fair-value provisions of FAS 123. We do not have any transition issues and, accordingly, we do not believe FAS 148 will have a material impact on our financial condition and results of operations.

 

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In November 2002, the FASB issued FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and Interpretation of FASB Statements Nos. 5, 57, and 107 and recession of FASB Interpretation No. 34”. FIN 45 requires: (1) the guarantor of debt to recognize a liability, at the inception of the guarantee, for the fair value of the obligation undertaken in issuing this guarantee, (2) indirect guarantees of debt to be recognized in the financial statements of the guarantor and (3) the guarantor to disclose the background and nature of the guarantee, the maximum potential amount to be paid under the guarantee, the carrying value of the liability associated with the guarantee and any recourse of the guarantor to recover amounts paid under the guarantee from third parties. FIN 45 rescinds all the provisions of FIN 34, “Disclosure of Indirect Guarantees of Indebtedness of Others”; as it has been incorporated into the provisions of FIN 45. The provisions of FIN 45 are effective for all guarantees issued or modified subsequent to December 31, 2002. The disclosure requirements of FIN 45 are effective for the financial statements of interim and annual periods ending after December 15, 2002. We do not have any commitments within the scope of FIN 45.

 

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”. The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities” or “VIEs”) and how to determine when and which business enterprise should consolidate the VIE (the “primary beneficiary”). This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures. FIN 46 may require more enterprises to consolidate entities with which they have contractual, ownership, or other pecuniary interests that absorb a portion of that entity’s expected losses or receive a portion of the entity’s residual returns. We are not the primary beneficiary of any VIEs.

 

2.                                      Merger Agreement

 

We and UtiliCorp United, Inc. (now known as Aquila, Inc.), entered into an Agreement and Plan of Merger, dated as of May 10, 1999 (the “Merger Agreement”), which provided for a merger of the Company with and into Aquila, with Aquila being the surviving corporation (the “Merger”). Our shareholders approved the proposed merger on September 3, 1999.

 

Under the terms of the Merger Agreement, either company could terminate the Merger Agreement without penalty if all regulatory approvals were not obtained prior to December 31, 2000. On January 2, 2001, Aquila exercised its right to terminate the Merger Agreement on that basis. Upon termination of the Merger Agreement, approximately $6.1 million of merger-related costs that had not been deductible for income tax purposes became deductible. As a result, we recognized a tax benefit related to such costs of approximately $2.3 million in the first quarter of 2001.

 

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The stockholder approval of the merger effected a change in control under our Change in Control Severance Pay Plan (the “Plan”). Certain key employees, electing voluntary termination, became eligible to receive compensation as specified under the terms of the Plan. The termination of the Merger Agreement did not relieve us of our obligations under the Plan. As of December 31, 2000, we had incurred approximately $155,000 of obligations to individuals electing voluntary termination under the Plan. Subsequent to that date, we incurred approximately $1,967,000 in additional obligations under the Plan. As of December 31, 2002 approximately $739,000 of the obligations had been paid and $1,383,000 remained. These remaining obligations will be paid over a three-year period.

 

3.                                      Acquisition of Non-Regulated Businesses

 

On July 17, 2002 EDE Holdings, Inc., a Company subsidiary, together with other investors, acquired the assets of the Precision Products Department of Eagle Picher Technologies, LLC, a manufacturer of close-tolerance metal products whose customers are in the aerospace, electronics, telecommunications, and machinery industries. The acquisition was accomplished through the creation of a newly formed, non-regulated limited liability company, Mid-America Precision Products (MAPP). EDE Holdings acquired a controlling 50.01% interest in this newly formed company through a cash investment of $650,000. EDE Holdings is also the 50.01% guarantor of a $2.6 million long-term note payable. The acquisition was accounted for using the purchase method of accounting in accordance with SFAS No. 141, “Business Combinations” (FAS 141).

 

Current assets were valued based on the carrying value at July 17, 2002. The property, plant and equipment was valued through a third party appraisal.

 

For the period of July 17, 2002 through December 31, 2002, MAPP’s operating income was $0.3 million and revenues were $7.7 million.

 

4.                                      Regulatory Matters

 

During the three years ending December 31, 2002, the following rate changes were requested or are in effect:

 

Missouri

On November 3, 2000, we filed a request with the MoPSC for a general annual increase in base rates for our Missouri electric customers in the amount of $41,467,926, or 19.36%. The MoPSC issued a final order on September 20, 2001 granting us an annual increase in rates of approximately $17.1 million, or 8.4%, effective October 2, 2001. In addition, the order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later. This IEC was collected subject to refund (with interest) at the end of the two-year period to the extent money was collected from customers above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates.

 

A one-time write-down of $4,100,000 was taken in the third quarter of 2001 for disallowed capital costs related to the construction of the State Line Combined Cycle Unit. These costs were disallowed as part of a stipulated agreement approved by the MoPSC in connection with our

 

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2001 rate case and are not recoverable in rates. The net effect on 2001 earnings after considering the tax effect on this write-down was $2,500,000.

 

In accordance with Statement of Financial Accounting Standards FAS No. 71, we have deferred approximately $660,000 of expense directly related to Missouri rate cases. We amortize this amount over varying periods.

 

On March 8, 2002, we filed a request with the MoPSC for an annual increase in base rates for our Missouri electric customers in the amount of $19,779,916 and also asked to have the IEC put into effect in the last rate case reconfigured to reflect a decrease of $9,994,888 in the amount to be billed to customers. The reconfigured IEC would remain subject to refund with interest. This request sought to recover new operating costs and obligations and reflect the changes in our capital structure since the rate increase in October 2001. Also on March 8, 2002, we filed an interim rate case for an annual increase in base rates of $3,562,983, the amount that was erroneously omitted from the increase granted in our 2001 rate case. The MoPSC rejected the interim request. After extensive negotiations with the MoPSC staff, Office of Public Counsel and other intervening parties, we filed a Unanimous Stipulation and Agreement Regarding “Error” in the 2001 rate case and an Immediate Reduction of the IEC with the MoPSC on May 14, 2002. This agreement was approved by the MoPSC on June 4, 2002 and provided for a $7 million annual reduction in the IEC.

 

On October 29, 2002, we filed a Unanimous Stipulation and Agreement, agreed to by the MoPSC staff, Office of Public Counsel and other intervening parties, with the MoPSC. This Agreement was approved by the MoPSC on November 22, 2002 and settled all matters covered by our March 2002 filings, provided us with an annual increase in rates of approximately $11.0 million, or 4.97%, effective December 1, 2002 and eliminated the IEC as of that date. The Agreement also calls for us to refund all funds collected under the IEC, with interest, by March 15, 2003. At December 31, 2002, we had recorded a current liability of approximately $18.7 million for such rate refunds. We collected $2.8 million in 2001 and recorded $0.75 million as revenue. We collected $15.9 million in 2002 and recorded a revenue reduction of ($0.75) million associated with the revenue recognized in 2001 because it became certain that the entire amount of IEC revenues collected would be refunded. As a result, we have recognized no revenue for combined 2001 and 2002 associated with the IEC collections. The remainder of the funds collected in 2001 and 2002 were set aside as a provision for rate refunds and not recognized in operating revenue. As a result of the non-recognition of these funds, the refunds have already been reflected in our results (except for $0.3 million of interest) and will have no material impact on our earnings in 2003. The Agreement also provided for a change to the summer/winter rate differential for our residential customers with the new rates reflecting a smaller differential between summer and winter rates for usage above 600 kilowatt hours. Each of the parties to the Agreement also agreed not to file a new request for a general rate increase or decrease before September 1, 2003, barring any unforeseen, extraordinary occurrences.

 

On May 15, 2002, we filed a request with the MoPSC for an annual increase in base rates for our Missouri water customers in the amount of approximately $361,000, or 33.9%. This was the first requested increase in rates for our water customers since 1994. On November 7, 2002, we filed an Agreement Regarding Disposition of a Small Company Rate Increase Request, agreed to by the Commission staff, with the MoPSC. This agreement was approved by the MoPSC effective

 

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December 23, 2002 and provides us with an annual increase in rates of approximately $358,000, or 33.7%.

 

Kansas

On December 28, 2001, we filed a request with the Kansas Corporation Commission (KCC) for an annual increase in base rates for our Kansas electric customers in the amount of $3,239,744, or 22.81%. This request sought to recover costs associated with our investment in State Line Unit No. 1, State Line Unit No. 2 and the State Line Combined Cycle Unit (SLCC), as well as significant additions to our transmission and distribution systems and operating cost increases which had occurred since our last rate increase in September 1994. We also requested reinstatement of a fuel adjustment clause for our Kansas rates. We filed a Unanimous Stipulation and Agreement, agreed to by the KCC staff and all intervening parties, with the KCC on June 7, 2002. The Agreement stipulates that we will not file for general rate relief before November 1, 2003 barring any unforeseen, extraordinary occurrences. This Agreement was approved by the KCC on June 27, 2002 providing us an annual increase in rates of approximately $2,539,000, or 17.87%, effective July 1, 2002. It did not provide for the reinstatement of a fuel adjustment clause.

 

Oklahoma

On March 4, 2003, we filed a request with the Oklahoma Corporation Commission (OCC) for an annual increase in base rates for our Oklahoma electric customers in the amount of $954,540, or 12.97%.

 

FERC

We are currently discussing an increase in rates with our on-system wholesale electric customers, and will make a FERC rate filing in 2003.

 

We recorded the following regulatory assets and regulatory liability, which are being amortized over periods of up to 25 years:

 

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Deregulation

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 electric utility industry. However, none of the states in our service territory have passed legislation that could require competitive pricing to be put into effect. The Arkansas Legislature passed a bill in April 1999 that called for deregulation of the state’s electricity industry as early as January 2002. However, a law was passed in February 2003 repealing deregulation in the state of Arkansas.

 

5.                                      Common Stock

 

On May 22, 2002, we sold 2,500,000 shares of our common stock in an underwritten public offering for $20.75 per share. This sale resulted in proceeds of approximately $49,433,000, net of issuance costs of $2,442,000.

 

On December 10, 2001, we sold 2,012,500 shares of our common stock in an underwritten public offering for $20.37 per share. This sale resulted in proceeds of approximately $38,961,000, net of issuance costs of $2,034,000.

 

In 1998, we implemented a stock unit plan for directors (the Director Retirement Plan) to provide directors the opportunity to accumulate retirement benefits in the form of common stock units in

 

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lieu of cash. The Director Retirement Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. A total of 200,000 shares are authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock upon retirement by the Director. The number of units granted annually is computed by dividing the director’s retainer fee 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. During 2002, 6,466 units were granted under the Director Retirement Plan for services provided in 2002, and 3,879 units were granted pursuant to the provisions of the Plan providing for the reinvestment of dividends on stock units in additional stock units.

 

Our Dividend Reinvestment and Stock Purchase Plan (the Reinvestment Plan), which was implemented June 1, 2001 (replacing the plan discontinued as of October 1, 2000), allows holders of common stock to reinvest dividends paid by us into newly issued shares of our common stock at 97% of the market price average of the high and low market price for each of the three trading days immediately preceding the dividend payment. Stockholders are also allowed to purchase on a weekly basis, for cash and within specified limits, additional stock at 100% of the market price average of the high and low price on the day of purchase. Participants in the Reinvestment Plan pay nominal service charges in connection with purchases under the Reinvestment 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. Contingent employee stock purchase subscriptions outstanding and the maximum prices per share were 40,574 shares at $17.91, 46,419 shares at $17.73, 40,880 shares at $21.83 on December 31, 2002, 2001 and 2000, respectively. Shares were issued at $17.73 per share in 2002, $17.78 per share in 2001 and $21.26 per share in 2000.

 

Our 1996 Incentive Plan (the Stock Incentive Plan) provides for the grant of up to 650,000 shares of common stock through January 2006. The terms and conditions of any option or stock grant are determined by the Board of Directors’ Compensation Committee, within the provisions of the Stock Incentive Plan. The 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. During February 2002, February 2001 and February 2000, grants for 2,669, 2,835 and 2,160 shares, respectively, of restricted stock were made to qualified employees under the Stock Incentive Plan. For grants made to date, the restrictions typically lapse and the shares are issuable to employees who continue in service with us three years from the date of grant. For employees whose service is terminated by death, retirement, disability, or under certain circumstances following a change in control of the Company prior to the restrictions lapsing, the shares are issuable immediately upon such termination. For other terminations, the grant is forfeited. During 2002, 2001 and 2000, 7,952, 4,648 and 3,368 shares, respectively, were issued under the Stock Incentive Plan.

 

In February 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 shareholders of Empire over a three-year period compared with an

 

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investor-owned utility peer group. Under the award for 2002, a maximum of 37,800 shares could be issued.

 

During 2002, we adopted SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – and Amendment of SFAS 123” (FAS 148) and elected to adopt the accounting provision of FAS 123 “Accounting for Stock-Based Compensation”. Under FAS 123, we will recognize compensation expense over the vesting period of all future stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance.

 

Prior to 2002, no options had been granted under the Stock Incentive Plan. During 2002, options consisting of the right to purchase 69,700 shares of common stock were issued under the Stock Incentive Plan to qualified individuals. The options were 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. The exercise price for the options outstanding at December 31, 2002 was $20.95. Dividend equivalent awards were also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes exercisable and will then be converted to restricted shares of our common stock based on the fair market value of the shares on the date converted. Such restricted shares vest on the eighth anniversary of the grant of the dividend equivalent award or, if earlier, upon exercise of the related option in full. The restricted shares are subject to forfeiture if the related option terminates without having been exercised in full prior to the vesting of these shares. The value of the options granted during 2002 was determined using the Black-Scholes pricing method and resulted in the Company recognizing $0.1 million in compensation expense in 2002.

 

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 annual compensation. We contributed 40,086, 35,793 and 33,926 shares of common stock in 2002, 2001 and 2000, respectively, valued at market prices on the dates of contributions. The stock issuances to effect the contributions were not cash transactions and are not reflected as a financing source of cash in the Statement of Cash Flows.

 

At December 31, 2002, 2,524,568 shares remain available for issuance under the foregoing plans.

 

 

6.                                      Preferred and Preference Stock

 

We have 2,500,000 shares of preference stock authorized, including 500,000 shares of Series A Participating Preference Stock, none of which have been issued. We have 5,000,000 shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2002 or 2001.

 

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On March 1, 2001 Empire District Electric Trust I, a wholly owned trust, issued 2,000,000 of its 8.5% Trust Preferred Securities. Due to the nature of these manditorily redeemable securities, the Company classified $50,000,000 at December 31, 2001 as long-term debt (see Note 7).

 

Preference Stock Purchase Rights

On April 27, 2000, the Board of Directors approved a new shareholder rights plan replacing an existing shareholder rights plan that expired on July 25, 2000. The new shareholder rights plan provides each of the common stockholders one Preference Stock Purchase Right (“Right”) for each share of common stock owned as compared to one-half of one right per common share under the prior shareholder rights plan. 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 22,509,230 and 19,703,837 Rights outstanding at December 31, 2002 and 2001, 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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7.                                      Long-Term Debt

 

At December 31, 2002 and 2001 the balance of long-term debt outstanding was as follows:

 

		2002			2001
Company obligated mandatorily redeemable Trust Preferred Securities of subsidiary holding solely parent debentures		$	50,000,000		$	50,000,000
Other:
First mortgage bonds:
7-1/2% Series due 2002		—			37,500,000
7.60% Series due 2005		10,000,000			10,000,000
8-1/8% Series due 2009		20,000,000			20,000,000
6-1/2% Series due 2010		50,000,000			50,000,000
7.20% Series due 2016		25,000,000			25,000,000
9-3/4% Series due 2020		2,250,000			2,250,000
7% Series due 2023		45,000,000			45,000,000
7-3/4% Series due 2025		30,000,000			30,000,000
7-1/4% Series due 2028(1)		13,076,000			13,154,000
5.3% Pollution Control Series due 2013		8,000,000			8,000,000
5.2% Pollution Control Series due 2013		5,200,000			5,200,000
		$	208,526,000		$	246,104,000
Senior Notes, 7.70% Series due 2004		100,000,000			100,000,000
Senior Notes, 7.05% Series due 2022(2)		50,000,000			—
Long-Term Debt – Mid-America Precision Products(3)		2,723,389			—
Obligations under capital lease		656,761			725,644
Less unamortized net discount		(477,040		)	(556,637		)
		411,429,110			396,273,007
Less current obligations of long-term debt		(236,872		)	(37,500,000		)
Less current obligations under capital lease		(194,143		)	(158,329		)
Total long-term debt		$	410,998,095		$	358,614,678

 

(1)               During the twelve-month period ending May 31 of each year, we are required to repurchase up to $25,000 in principal amount of the bonds of this series per holder per year, upon the death of such holder. We are not required to repurchase more than $217,500 in the aggregate in any twelve-month period. At December 31, 2002 we had repurchased a total of $1,424,000 of bonds related to this requirement.

 

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(2)               We may redeem some or all of the notes at any time and from time to time on or after December 15, 2006 at 100% of their principal amount, plus accrued and unpaid interest to the redemption date. During each twelve-month period ending December 15, we are required to repurchase up to $25,000 in principal amount of the notes of this series per holder per year, upon the death of the holder. We are not required to repurchase more than $1,000,000 in the aggregate in any twelve-month period. At December 31, 2002, we had not repurchased any of the notes related to this requirement.

 

(4)               EDE Holdings is the guarantor of 50.01% of a secured long-term note payable of MAPP. The 2002 current obligations of long-term debt represent the current obligation of this debt.

 

On March 1, 2001, Empire District Electric Trust I issued 2,000,000 of its 8.5% Trust Preferred Securities (liquidation amount $25 per preferred security) in a public underwritten offering. This issuance generated proceeds of $50,000,000 and issuance costs of approximately $1,885,000. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8.5% 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 8.5% 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 fully and unconditionally guaranteed the payments due on the outstanding trust preferred securities. The net proceeds of this offering were added to our general funds and were used to repay short-term indebtedness.

 

The principal amount of all series of first mortgage bonds outstanding at any one time is limited by terms of the mortgage to $1,000,000,000. Substantially all of EDEC’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 indenture) for any twelve consecutive months within the 15 months preceding issuance must be two times the annual interest requirements (as defined in the indenture) 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, 2002 would permit us to issue $187.2 million of new first mortgage bonds based on this test. The indenture provides an exception from this earnings requirement in certain instances, relating to the issuance of first mortgage bonds which have been or are to be retired. We are in compliance with all restrictive covenants of our first mortgage bonds debt agreements.

 

On December 23, 2002, we sold to the public in an underwritten offering $50 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022. The net proceeds of this sale were added to our general funds and were used to repay short-term indebtedness.

 

The carrying amount of our long-term debt exclusive of capital leases was $410,535,477 and $395,547,363 at December 31, 2002 and 2001, respectively, and its fair market value was estimated to be approximately $414,125,000 and $387,828,000, 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 maturation. 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.

 

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Payments Due by Period

 

(in millions)

 

Long-Term Debt Payout Schedule (Excluding Unamortized Discount)		Total				Less than 1 Year			1-3 Years			3-5 Years			More than  5 Years
Company obligated mandatorily  redeemable trust preferred securities  of subsidiary holding solely parent  debentures		$	50.0			$	—		$	—		$	—		$	50.0
Long-term debt		358.5				—			110.0			—			248.5
Capital lease obligations		0.7				0.2			0.5			—			—
Other long-term obligations		2.7				0.2			0.5			2.0			—
Total long-term debt obligations		$		411.9		$	0.4		$	111.0		$	2.0		$	298.5
Less current obligations and unamortized discount		0.9
Total long-term debt		$		411.0

 

8.                                      Short-term Borrowings

 

Short-term commercial paper outstanding and notes payable averaged $46,551,748 and $58,390,882 daily during 2002 and 2001, respectively, with the highest month-end balances being $62,000,000 and $80,000,000, respectively. The weighted daily average interest rates during 2002, 2001 and 2000 were 2.4%, 4.6% and 7.0%, respectively. The weighted average interest rates of borrowings outstanding at December 31, 2002 and 2001 were 2.0% and 2.8%, respectively. At December 31, 2002, we had outstanding commercial paper of $22,541,000 with due dates from January 2, 2003 to January 30, 2003.

 

At December 31, 2002, we had a 370-day $100,000,000 unsecured revolving credit facility. Borrowings are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current ratings and the pricing schedule in the line of credit document. We may borrow at our discretion from time to time during the period from May 7, 2002 to and including May 12, 2003, the revolving credit termination date. The credit facility is used for working capital, general corporate purposes and to back-up use of commercial paper. This facility requires our total Indebtedness (which does not include our Trust Preferred Securities) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes distributions on our Trust Preferred Securities) 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, 2002, we are in compliance with these ratios. This credit facility is also subject to cross-default with our other indebtedness (in excess of $5,000,000 in the aggregate). This arrangement does not serve to legally restrict the use of our cash. There were no outstanding borrowings under this agreement at December 31, 2002. However, $22,541,000 of the facility as of that date was used to back up our commercial paper and was not available to be borrowed.

 

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9.                                      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.

 

Our pension expense or benefit includes amortization of previously unrecognized net gains or losses as a result of requirements of the September 20, 2001 MoPSC rate case. The amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years. The Company’s policy is consistent with the provisions of SFAS 87, “Employers’ Accounting for Pensions” (FAS 87).

 

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, healthcare cost trend rates and discount rates.

 

The following table sets forth the plan’s projected benefit obligation, the fair value of the plan’s assets and its funded status:

 

		2002				2001				2000
Benefit obligation at beginning of year		$		78,291,337		$		75,217,964		$		72,288,124
Service cost		2,190,415				2,172,379				2,182,798
Interest cost		5,601,019				5,604,231				5,579,276
Actuarial loss/(gain)		6,401,833				99,017				(250,025			)
Benefits paid		(5,010,057			)	(4,802,254			)	(4,582,209			)
Benefit obligation at end of year		$		87,474,547		$		78,291,337		$		75,217,964
Fair value of plan assets at beginning of year		$	92,138,446			$	98,898,066			$	104,485,842
Actual return on plan assets		(8,910,788			)	(1,957,366			)	(1,005,567			)
Benefits paid		(5,010,057			)	(4,802,254			)	(4,582,209			)
Fair value of plan assets at end of year		$		78,217,601		$		92,138,446		$		98,898,066

 

 

 

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		2002			2001			2000
Funded status		$	(9,256,946	)	$	13,847,109		$	23,680,102
Unrecognized net assets at January 1, 1986 being amortized over 17 years		—			(491,158		)	(982,313		)
Unrecognized prior service cost		3,227,779			3,747,210			4,266,641
Unrecognized net loss/(gain)		25,584,623			(1,129,486		)	(15,357,002		)
Prepaid pension cost		$	19,555,456		$	15,973,675		$	11,607,428

 

At December 31, 2002 our accumulated benefit obligation was $74,076,943 and our plan asset value was $78,217,601.

 

Assumptions used in calculating the projected benefit obligation for 2002, 2001 and 2000 include the following:

 

		2002		2001		2000
Weighted average discount rate		6.75	%	7.25	%	7.75	%
Rate of increase in compensation levels		4.00	%	4.00	%	5.00	%
Expected long-term rate of return on plan assets		9.00	%	9.00	%	9.00	%

 

Net pension benefit for 2002, 2001 and 2000 is comprised of the following components:

 

		2002			2001			2000
Service cost - benefits earned during the period		$	2,190,415		$	2,172,379		$	2,182,798
Interest cost on projected benefit obligation		5,601,019			5,604,231			5,579,276
Expected return on plan assets		(8,048,645		)	(8,672,012		)	(9,181,211		)
Net amortization		(3,324,570		)	(3,470,845		)	(6,361,360		)
Net pension income		$	(3,581,781	)	$	(4,366,247	)	$	(7,780,497	)

 

Other Postretirement Benefits

We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.

 

Effective January 1, 1993, we adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (FAS 106), which requires recognition of these benefits on an accrual basis during the active service period of the employees. We elected to amortize our transition obligation (approximately $21,700,000) related to FAS 106 over a twenty-year period. Prior to adoption of FAS 106, we recognized the cost of such postretirement benefits on a pay-as-you-go (i.e., cash) basis. The states of Missouri, Kansas, Oklahoma, and Arkansas authorize the recovery of FAS 106 costs through rates.

 

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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. Our funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefits costs allowed in rates. Assets in these trusts amounted to approximately $21,500,000 at December 31, 2002, $18,600,000 at December 31, 2001 and $16,100,000 at December 31, 2000.

 

Postretirement benefits, a portion of which have been capitalized for 2002, 2001 and 2000 included the following components:

 

		2002			2001			2000
Service cost on benefits earned during the year		$	1,141,158		$	828,316		$	931,469
Interest cost on projected benefit obligation		3,095,057			2,892,691			3,142,872
Return on assets		1,350,634			(1,260,307		)	(1,007,118		)
Amortization of unrecognized transition obligation		1,084,017			1,084,017			1,084,017
Unrecognized net (gain)/loss		896,316			407,068			1,990,806
Net periodic postretirement benefit cost		$	4,865,914		$	3,951,785		$	6,142,045

 

The estimated funded status of our obligations under FAS 106 at December 31, 2002, 2001 and 2000 using a weighted-average discount rate of 6.75%, 7.25% and 7.75%, respectively, is as follows:

 

		2002			2001			2000
Benefit obligation at beginning of year		$	42,315,384		$	37,251,254		$	28,669,028
Service cost		1,141,158			828,316			931,469
Interest cost		3,095,057			2,892,691			3,142,872
Actuarial (gain)/loss		9,029,864			2,757,072			5,908,539
Benefits paid		(1,780,913		)	(1,413,949		)	(1,400,654		)
Benefit obligation at end of year		$	53,800,550		$	42,315,384		$	37,251,254

 

 

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		2002			2001			2000
Fair value of plan assets at beginning of year		$	18,596,087		$	16,055,828		$	10,552,442
Employer contributions		5,233,834			3,951,785			5,735,695
Actual return on plan assets		(586,872		)	2,423			1,168,343
Benefits paid		(1,748,934		)	(1,413,949		)	(1,400,654		)
Fair value of plan assets at end of year		$	21,494,115		$	18,596,087		$	16,055,826
Funded status		$	(32,306,435	)	$	(23,719,297	)	$	(21,195,426	)
Unrecognized transition obligation		16,915,842			11,924,174			13,008,191
Unrecognized net gain		10,840,157			6,870,118			3,262,230
Accrued postretirement benefit cost		$	(4,550,436	)	$	(4,925,005	)	$	(4,925,005	)

 

The assumed 2003 cost trend rate used to measure the expected cost of healthcare benefits is 10%. The trend rate decreases through 2012 to an ultimate rate of 5% for 2013 and subsequent years. The effect of a 1% increase in each future year’s assumed healthcare cost trend rate would increase the current service and interest cost from $4,200,000 to $5,300,000 and the accumulated postretirement benefit obligation from $53,800,000 to $66,300,000. The effect of a 1% decrease in each future year’s assumed healthcare cost trend rate would decrease the current service and interest cost from $4,200,000 to $3,300,000 and the accumulated benefit obligation from $53,800,000 to $43,300,000.

 

 

10.           Income Taxes

 

The provision for income taxes is different from the amount of income tax determined by applying the statutory income tax rate to income before income taxes as a result of the following differences:

 

		2002			2001			2000
Computed “expected” federal provision		$	13,590,000		$	3,640,000		$	12,290,000
State taxes, net of federal effect		1,190,000			125,000			1,090,000
Adjustment to taxes resulting from:
Merger costs		—			(2,320,000		)	120,000
Investment tax credit amortization		(550,000		)	(550,000		)	(580,000		)
Other		(920,000		)	(895,000		)	(1,420,000		)
Actual provision for income taxes		$	13,310,000		$	—		$	11,500,000

 

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Income tax expense components for the years shown are as follows:

 

		2002			2001			2000
Taxes currently (receivable)/payable
Included in operating revenue deductions:
Federal		$	1,590,000		$	(50,000	)	$	8,852,000
State		170,000			30,000			1,203,000
Included in “other - net”		(80,000		)	(240,000		)	(28,000		)
		1,680,000			(260,000		)	10,027,000
Deferred taxes:
Depreciation and amortization differences		11,479,000			2,986,000			2,136,000
Loss on reacquired debt		(169,000		)	(203,000		)	(206,000		)
Postretirement benefits		559,000			844,000			1,408,000
Other		(964,000		)	(1,028,000		)	(1,158,000		)
Asbury five-year maintenance		902,000			(100,000		)	(241,000		)
Software development costs		(190,000		)	(252,000		)	(39,000		)
Included in “other - net”		563,000			120,000			153,000
Disallowed plant addition		—			(1,557,000		)	—
		12,180,000			810,000			2,053,000
Deferred investment tax credits, net		(550,000		)	(550,000		)	(580,000		)
Total income tax expense		$	13,310,000		$	—		$	11,500,000

 

Under SFAS No. 109, “Accounting for Income Taxes” (FAS 109), temporary differences gave rise to deferred tax assets and deferred tax liabilities at year end 2002 and 2001 as follows:

 

		Balances as of December 31,
		2002						2001
		Deferred Tax Assets			Deferred Tax Liabilities			Deferred Tax Assets			Deferred Tax Liabilities
Noncurrent
Depreciation and other property related		$	11,748,535		$	109,531,527		$	12,065,652		$	97,737,131
Unamortized investment tax credits		3,854,342			—			4,200,107			—
Miscellaneous book/tax recognition differences		7,198,842			16,414,743			7,137,872			10,292,446
Total deferred taxes		$	22,801,719		$	125,946,270		$	23,403,631		$	108,029,577

 

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11.          Commonly Owned Facilities

 

We own a 12% undivided interest in the Iatan Power Plant, a coal-fired, 670-megawatt generating unit near Weston, Missouri. Great Plains Energy Inc. and Aquila own 70% and 18%, respectively, of the Unit. We are entitled to 12% of the available capacity and are obligated for that percentage of costs included in the corresponding operating expense classifications in the Statement of Income. At December 31, 2002 and 2001, our property, plant and equipment accounts included the cost of our ownership interest in the plant of $48,338,000 and $46,139,000, respectively, and accumulated depreciation of $32,436,000 and $31,633,000, respectively.

 

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”). The State Line Combined Cycle Unit was placed into commercial operation on June 25, 2001. The total cost of the State Line Combined Cycle Unit was approximately $204,000,000, including the one-time non-cash charge of $4,100,000, before related income taxes, that was recorded in the third quarter of 2001 for disallowed capital costs. Our 60% share of this amount was approximately $122,000,000 before considering the contribution of 40% of existing property. After the transfer to WGI on June 15, 2001 of an undivided 40% joint ownership interest in the existing State Line Unit No. 2 and certain other property at book value, our net cash requirement was approximately $108,000,000, excluding AFUDC. We are responsible for the operation and maintenance of the State Line Combined Cycle Unit and for 60% of its costs. The State Line Combined Cycle Unit provides us with approximately 150 megawatts of additional capacity. At December 31, 2002 and 2001, our property, plant and equipment accounts include the cost of our ownership interest in the unit of $153,103,000 and $156,194,000, respectively, and accumulated depreciation of $9,700,000 and $5,540,000, respectively.

 

 

12.                               Commitments and Contingencies

 

By letters dated October 31, 2002 and January 17, 2003, Enron North America Corp. (Enron) and their counsel demanded that the we pay Enron $6,113,850, an amount which Enron claimed it is owed as a result of our early termination of all transactions under the Enfolio Master Firm Purchase/Sale Agreement dated June 1, 2001 between us and Enron. We dispute that any amounts are owed to Enron as a result of such termination and have responded to Enron stating that there was no contractual basis for Enron to assert that it was entitled to any such payment. We intend to vigorously oppose any attempt by Enron to collect the claimed amounts.

 

We are a party to various claims and legal proceedings arising out of the normal course of our business. In the opinion of management, the ultimate outcome of these claims and lawsuits will not have a material adverse affect upon our financial condition, or results of operations or cash flows.

 

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 and transportation commitments total $12.7 million for 2003, $25.3 million for 2004 through 2006,

 

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and $55.8 million for 2007 and beyond. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price.

 

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for 2003, 2004 and 2005 are $16.1 million, $22.6 million and $8.0 million, respectively.

 

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 $16.2 million per year through May 31, 2010. We also have a short-term contract with American Electric Power from January 1, 2003 through March 31, 2003. Commitments under this contract total approximately $5 million for the period.

 

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13.           Selected Quarterly Information (Unaudited)

 

A summary of operations for the quarterly periods of 2002 and 2001 is as follows:

 

		Quarters
		First			Second			Third			Fourth
		(dollars in thousands except per share amounts)
2002:
Operating revenues		$	65,297		$	68,905		$	99,823		$	71,878
Operating income		7,644			11,783			26,258			10,383
Net income		(537		)	4,027			18,387			3,647
Net income applicable
to common stock		(537		)	4,027			18,387			3,647
Basic and diluted earnings
per average share of
common stock		$	(.03	)	$	.19		$	.82		$	.16

 

		Quarters
		First			Second			Third			Fourth
		(dollars in thousands except per share amounts)
2001:
Operating revenues		$	60,974		$	58,695		$	83,821		$	62,331
Operating income		8,409			7,527			18,414			8,862
Net income		2,207			741			7,359			96
Net income applicable
to common stock		2,207			741			7,359			96
Basic and diluted earnings
per average share of
common stock		$	.13		$	.04		$	.42		$	.01

 

The sum of the quarterly earnings per average share of common stock may not equal the earnings per average share of common stock as computed on an annual basis due to rounding. Operating revenues and operating income amounts may not agree with amounts previously reported due to minor reclassifications.

 

14.                               Risk Management and Derivative Financial Instruments

 

On January 1, 2001, we adopted the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133) and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities and Amendment of SFAS 133” (FAS 138). FAS 133, as amended, requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. We utilize derivatives to manage our natural gas commodity market risk to help manage our exposure resulting from purchasing natural gas on the volatile spot market.

 

FAS 133 requires all derivatives to be recognized on the balance sheet at their fair value. On the date the 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

 

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highly effective and designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are recorded in earnings). Changes in the fair value of non-hedged derivative instruments are reported in current-period earnings.

 

We discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer 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 designated as a hedge 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.

 

As of December 31, 2002, 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.

 

Current assets		$	5,983,490
Noncurrent assets		$	16,949,388
Current liabilities		$	64,000
Noncurrent liabilities		$	10,914,668

 

A $6,643,467 net of tax, unrealized gain representing the fair market value of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The tax effect of $4,071,803 on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis until the determination periods beginning January 1, 2003 and ending on December 31, 2004. At the end of each determination period any gain or loss for that period related to the contract will be reclassified to fuel expense.

 

As of December 31, 2002, $1,238,940 of unrealized gains relating to non-qualifying hedging instruments has been recognized within other income and deductions in the accompanying statement of income. This gain resulted from anticipated natural gas usage that was financially hedged but no longer necessary because we were able to purchase power in the wholesale market more economically than generating it ourselves.

 

As of December 31, 2002, $52,210 of realized losses relating to non-qualifying hedging instruments has been recognized within other income and deductions in the accompanying statement of income.

 

We have also entered into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the reporting requirements of FAS 133 because they are considered to be normal purchases and normal sales.

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

 

None

 

PART III

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

 

The information required by this Item with respect to directors and directorships and with respect to Section 16(a) Beneficial Ownership Reporting Compliance may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 24, 2003, 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.”

 

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 24, 2003, 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 24, 2003, 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 one plan approved by shareholders, the 1996 Stock Incentive Plan, and one plan not approved by shareholders, the Stock Unit Plan for Directors.

 

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The following table summarizes information about our equity Compensation Plans as of December 31, 2002.

 

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(2)			(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		109,589		$	20.95		514,479
Equity compensation plans not approved by security holders(1)		57,949		—			133,893
Total		167,538		$	20.95		648,372

 

(1)          The Stock Unit Plan for Directors was approved by the Company’s Board of Directors on July 23, 1998. This plan as amended, reserved up to 200,000 shares of the Company’s common stock for issuance under the plan. There is no exercise price for the stock units. For a description of this plan, See Note 5 of “Notes to Financial Statements” under Item 8.

 

(2)          The weighted average exercise price of $20.95 relates to 69,700 options granted to executive officers in 2002 under the 1996 Stock Incentive Plan. There is no exercise price for 2,089 shares of restricted stock and 37,800 performance-based stock awards awarded under the 1996 Stock Incentive Plan or for the 57,949 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 24, 2003, which is incorporated herein by reference.

 

ITEM 14.  CONTROLS AND PROCEDURES

 

Within the 90-day period prior to the date of this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information to be required to be disclosed by us in reports that we file or submit under the Exchange Act.

 

There have been no significant changes in the our internal controls or in other factors that could significantly affect internal controls subsequent to the date of the evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

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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 Auditors

 

Consolidated balance sheets at December 31, 2002 and 2001

Consolidated statements of income for each of the three years in the period ended December 31, 2002

Consolidated statements of comprehensive income for each of the three years in the period ended December 31, 2002

Consolidated statements of common stockholders’ equity for each of the three years in the period ended December 31, 2002

Consolidated statements of cash flows for each of the three years in the period ended December 31, 2002

Notes to consolidated financial statements

Schedule for the years ended December 31, 2002, 2001 and 2000:

Schedule II – Valuation and qualifying accounts

 

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

 

(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.*
(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)		-		Seventeenth Supplemental Indenture dated as of December 1, 1990 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(j) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1-3368).
		(f)		-		Twentieth Supplemental Indenture dated as of June 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Form S-3, File No. 33-66748).
		(g)		-		Twenty-First Supplemental Indenture dated as of October 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 1993, File No. 1-3368).
		(h)		-		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).
		(i)		-		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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		(j)		-		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).
		(k)		-		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).
		(l)		-		Twenty-Sixth Supplemental Indenture dated as of April 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1995, File No. 1-3368).
		(m)		-		Twenty-Seventh Supplemental Indenture dated as of June 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended June 30, 1995, File No. 1-3368).
		(n)		-		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).
		(o)		-		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).
		(p)		-		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).
		(q)		-		Securities Resolution No. 1, dated as of November 16, 1999, of Empire under the Indenture for Unsecured Debt Securities. (Incorporated by reference to Exhibit 4(r) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-3368)
		(r)		-		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)
		(s)		-		Securities Resolution No. 3, dated as of December 18, 2002, of Empire under the Indenture for Unsecured Debt Securities.*
		(t)		-		370-Day $100,000,000 Unsecured Credit Agreement, dated as of May 7, 2002, 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 March 31, 2002, File No. 1-3368).
		(u)		-		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).
(10)		(a)		-		1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639).†
		(b)		-		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). †
		(c)		-		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). †
		(d)		-		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). †
		(e)		-		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) †

 

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		(f)		-		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). †
		(g)		-		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). †
		(h)		-		Stock Unit Plan for Directors (Incorporated by reference to Exhibit 10(b) to Form Q for quarter ended September 30, 1998, File No. 1-3368). †
		(i)		-		First Amendment to Stock Unit Plan for Directors, dated as of January 1, 2002 (Incorporated by reference to Exhibit 10(a) to Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-3368). †
(12)				-		Computation of Ratios of Earnings to Fixed Charges.*
(21)				-		Subsidiaries of Empire*
(23)				-		Consent of PricewaterhouseCoopers LLP*
(24)				-		Powers of Attorney.*
(99)		(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.*
(99)		(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

 

Reports on Form 8-K

 

(a)          In a current report dated November 15, 2002, Empire filed, under Item 5. “Other Events,” a press release relating to our rate increase for our Missouri electric customers and the Report and Order from the Missouri Public Commission.

 

(b)         In a current report dated December 18, 2002, Empire filed, under Item 5. “Other Events,” a press release relating to our rate increase for our Missouri water customers.

 

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SCHEDULE II

Valuation and Qualifying Accounts

 

Years ended December 31, 2002, 2001 and 2000

 

		Balance At Beginning of period			Additions								Deductions from reserve					Balance at close of period
								Charged to Other Accounts
					Charged to income			Description		Amount			Description		Amount
Year ended December 31, 2002:
Reserve deducted from assets:								Recovery of amounts previously written off					Accounts written off
Accumulated provision for uncollectible accounts		$	894,707		$	1,254,932				$	915,156				$	2,386,068		$	678,727
Reserve not shown separately in balance sheet:								Property, plant & equipment and clearing accounts					Claims and expenses
Injuries and damages reserve (Note A)		$	1,396,670		$	527,971				$	527,971				$	1,055,942		$	1,396,670
Year ended December 31, 2001:
Reserve deducted from assets:								Recovery of amounts previously written off					Accounts written off
Accumulated provision for uncollectible accounts		$	963,536		$	1,991,000				$	1,030,497				$	3,090,632		$	894,707
Reserve not shown separately in balance sheet:								Property, plant & equipment and clearing accounts					Claims and expenses
Injuries and damages reserve (Note A)		$	1,400,000		$	555,580				$	555,580				$	1,114,490		$	1,396,670
Year ended December 31, 2000:
Reserve deducted from assets:								Recovery of amounts previously written off					Accounts written off
Accumulated provision for uncollectible accounts		$	371,946		$	1,313,547				$	77,371				$	799,328		$	963,536
Reserve not shown separately in balance sheet:								Property, plant & equipment and clearing accounts					Claims and expenses
Injuries and damages reserve (Note A)		$	1,000,000		$	722,200				$	722,200				$	1,044,400		$	1,400,000

NOTE A:                        This reserve is provided for workers’ compensation, certain postemployment benefits and public liability damages. Empire at December 31, 2002 carried insurance for workers’ compensation claims in excess of $250,000 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
	By	/s/ WILLIAM L. GIPSON
		W. L. Gipson, President
Date:  March 6, 2003

 

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.

 

 

	W. L. GIPSON	Date
	W. L. Gipson, President and Director
	(Principal Executive Officer)
	G. A. KNAPP
	G. A. Knapp, Vice President-Finance
	(Principal Financial Officer)
	D. L. COIT
	D. L. Coit, Controller and Assistant Treasurer and Assistant Secretary
	(Principal Accounting Officer)
	J. S. LEON*
	J. S. Leon, Director
	M. F. CHUBB, JR.*
	M. F. Chubb, Jr., Director
	M. W. MCKINNEY*
	M. W.McKinney, Director
	R. C. HARTLEY*		March 6, 2003
	R. C. Hartley, Director
	J. R. HERSCHEND*
	J. R. Herschend, Director
	F. E. JEFFRIES*
	F. E. Jeffries, Director
	B. T. MUELLER*
	B. T. Mueller, Director
	R. L. LAMB*
	R. L. Lamb, Director
	M. M. POSNER*
	M. M. Posner, Director
*By	G. A. KNAPP
	(G. A. Knapp, As attorney in fact for each of the persons indicated)

 

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CERTIFICATIONS

 

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

 

I, William L. Gipson, certify that:

 

1.  I have reviewed this annual report on Form 10-K of The Empire District Electric Company;

 

2.  Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

 

3.  Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

 

4.  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

 

a)  designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

 

b)  evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c)  presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.  The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

a)  all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b)  any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

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6.  The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Date:  March 6, 2003

 

By:	/s/ William L. Gipson
Name:  William L. Gipson
Title:  President and Chief Executive Officer

 

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CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

 

I, Gregory A. Knapp, certify that:

 

1.  I have reviewed this annual report on Form 10-K of The Empire District Electric Company;

 

2.  Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

 

3.  Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

 

4.  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

 

a)  designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

 

b)  evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c)  presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.  The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

a)  all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b)  any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

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6.  The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Date:  March 6, 2003

 

By:	/s/ Gregory A. Knapp
Name:  Gregory A. Knapp
Title:  Vice President - Finance and Chief Financial Officer

 

75