UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1998 or
Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______________ to ____________.
Commission file number: 1-3368
THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Kansas 44-0236370
(State of Incorporation) (I.R.S. Employer
Identification No.)
602 Joplin Street, Joplin, Missouri 64801
(Address of principal executive offices) (zip code)
Registrant's telephone number: (417) 625-5100
Securities registered pursuant to Section 12(b) of the Act:
Name of each
Title of each class exchange on
which registered
Common Stock ($1 par value) New York Stock
Exchange
5% Cumulative Preferred Stock ($10 New York Stock
par value) Exchange
4-3/4% Cumulative Preferred Stock New York Stock
($10 par value) Exchange
8-1/8% Cumulative Preferred Stock New York Stock
($10 par value) Exchange
Preference Stock Purchase Rights New York Stock
Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes x No ___
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. [x]
As of March 1, 1999, 17,081,019 shares of common stock were outstanding.
Based upon the closing price on the New York Stock Exchange on March 1,
1999, the aggregate market value of the common stock of the Company held
by nonaffiliates was approximately $392,863,437.
The following documents have been incorporated by reference into the
parts of the Form 10-K as indicated:
The Company's proxy Part of Item 10 of Part
statement, filed pursuant III
To Regulation 14A under the All of Item 11 of Part
Securities Exchange III
Act of 1934, for its 1998 Part of Item 12 of Part
Annual Meeting of III
Stockholders to be held on All of Item 13 of Part
April 22, 1999. III
TABLE OF CONTENTS
Pag
e
PART I
ITEM BUSINESS 3
1.
General 3
Electric Generating Facilities and Capacity 3
Construction Program 4
Fuel 5
Employees 6
Electric Operating Statistics 7
Executive Officers and Other Officers of the Registrant 8
Regulation 8
Environmental Matters 9
Conditions Respecting Financing 10
ITEM PROPERTIES 11
2.
Electric 11
Facilities......................................................
................................................................
......................................
Water 12
Facilities......................................................
................................................................
.........................................
ITEM LEGAL PROCEEDINGS 12
3.
ITEM SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 12
4.
PART
II
ITEM MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED 13
5. STOCKHOLDER MATTERS
ITEM SELECTED FINANCIAL DATA 15
6.
ITEM MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
7. RESULTS OF 16
OPERATIONS
Results of 16
Operations......................................................
................................................................
................................
Liquidity and Capital 20
Resources.......................................................
................................................................
..............
Year 21
2000............................................................
................................................................
............................................
Forward Looking 23
Statements......................................................
................................................................
....................
ITEM QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 23
7A
ITEM FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 25
8.
ITEM CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
9. FINANCIAL 45
DISCLOSURE
PART
III
ITEM DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 45
10.
ITEM EXECUTIVE COMPENSATION 45
11.
ITEM SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 45
12.
ITEM CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 45
13.
PART
IV
ITEM EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 46
14.
SIGNATURES 49
PART I
ITEM 1. BUSINESS
General
The Empire District Electric Company (the "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. The Company also provides water service to three towns in
Missouri. In 1998, 99.6% of the Company's gross operating revenues
were provided from the sale of electricity and 0.4% from the sale
of water.
The territory served by the Company's electric operations
embraces an area of about 10,000 square miles with a population of
over 330,000. 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 industry,
agriculture and tourism. Of the Company's total 1998 retail
electric revenues, approximately 88% came from Missouri customers,
6% from Kansas customers, 3% from Oklahoma customers and 3% from
Arkansas customers.
The Company supplies 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 served by the
Company is the city of Joplin, Missouri, and its immediate
vicinity, with a population of approximately 135,000. The Company
operates under franchises having original terms of twenty years or
longer in virtually all of the incorporated communities.
Approximately 43% of the Company's electric operating revenues in
1998 were derived from incorporated communities with franchises
having at least ten years remaining and approximately 23% were
derived from incorporated communities in which the Company's
franchises have remaining terms of ten years or less. Although the
Company's franchises contain no renewal provisions, in recent years
the Company has obtained renewals of all of its expiring electric
franchises prior to the expiration dates.
The Company's electric operating revenues in 1998 were derived
as follows: residential 42%, commercial 30%, industrial 17%,
wholesale 7% and other 4%. Producers of food and kindred products
accounted for approximately 7% of electric revenues in 1998. The
Company's largest single on-system wholesale customer is the city
of Monett, Missouri, which in 1998 accounted for approximately 3%
of electric revenues. No single retail customer accounted for more
than 1% of electric revenues in 1998.
The Company made an investment of approximately $3.5 million
in 1998 and $1.8 million in 1997 in fiber optics cable and
equipment which the Company is using in its own operations and
leasing to other entities. The Company also offers electronic
monitored security services.
Electric Generating Facilities and Capacity
At December 31, 1998, the Company's generating plants
consisted of the Asbury Plant (aggregate generating capacity of 213
megawatts), the Riverton Plant (aggregate generating capacity of
136 megawatts), the Empire Energy Center (aggregate generating
capacity of 180 megawatts), the State Line Power Plant (aggregate
generating capacity of 253 megawatts) and the Ozark Beach
Hydroelectric Plant (aggregate generating capacity of 16
megawatts). The Company also has a 12% ownership interest (80
megawatt capacity) in Unit No. 1 at the Iatan Generating Station.
See Item 2, "Properties - Electric Facilities" for further
information about these plants. In order to reduce reliance on
purchased power to meet its future demands, the Company, in
cooperation with Western Resources, is currently planning to
construct a 350-megawatt expansion at the State Line Power Plant.
This expansion will consist of a 150-megawatt Westinghouse 501F
combustion turbine that will operate alongside the existing State
Line Unit II 152-megawatt combustion turbine. Exhaust heat from
these two units will be used to power a 200-megawatt steam turbine.
Combined output of all three units will be a nominal 500 megawatts.
The Company expects to be entitled to generating capacity of 300
megawatts from this expansion, replacing the 152 megawatts
currently available from State Line Unit II. Construction is
expected to begin in late 1999 with commercial operation scheduled
for June 2001. See "-Construction Program" and Item 7,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources" for
further information about this expansion.
The Company, formerly a member of the MOKAN Power Pool which
disbanded as of January 15, 1999, is currently a member of the
Southwest Power Pool ("SPP"), a regional division of the North
American Electric Reliability Council ("NERC"). The SPP requires
its members, including the Company, to maintain a 12% capacity
reserve margin effective October 1, 1998, and provides for
contingency reserve sharing, regional near real-time security
assessment 24 hours per day and many other functions. The Company
is also a member of the Western Systems Power Pool, a marketing
pool that provides agreements that facilitate the purchase and sale
of wholesale power among members. Most of the United States
electric utilities are now parties to this agreement.
The Company currently supplements its on-system generating
capacity with purchases of capacity and energy from neighboring
utilities in order to meet the demands of its customers and the
capacity margins applicable to it under current pooling agreements
and NERC rules. The Company has entered into agreements for such
purchases with Associated Electric Cooperative, Inc. ("AECI"),
Kansas Gas & Electric ("KG&E - a subsidiary of Western Resources)
and Southwestern Public Service Company ("SPS" - a subsidiary of
New Centuries Energies) for periods through the contract year 2000
which ends May 31, 2001. In addition, the Company has contracted
with Western Resources, Inc. ("Western Resources") for the purchase
of capacity and energy through May 31, 2010. The amount of capacity
purchased under these contracts supplements the Company's on-system
capacity and contributes to meeting its current expectations of
future power needs. The following chart sets forth the Company's
purchase commitments and anticipated owned capacity (in megawatts)
during the indicated contract years (which run from June 1 to May
31 of the following year). The reduction in purchased power
commitments in 2001 is the result of the expiration of the long-
term AECI purchase contract on May 31, 2001 and the installation of
the Company's share of the additional State Line generation that is
scheduled to be available by the summer of 2001.
Purchased Anticipated
Contract Power Owned
Year Commitment Capacity Total
1996 290 724 1014
1997 210 878 1088
1998 230 878 1108
1999 255 878 1133
2000 287 878 1165
2001 162 1026 1188
2002 162 1026 1188
2003 162 1026 1188
The charges for capacity purchases under the contracts referred to
above during calendar year 1998 amounted to approximately $14.1
million. Minimum charges for capacity purchases under such
contracts total approximately $91.6 million for the period June 1,
1999, through May 31, 2004.
The maximum hourly demand on the Company's system reached a
new record high of 916 megawatts on August 26, 1998. The Company's
previous record peak of 876 megawatts was established in July 1997.
The Company's maximum hourly winter demand of 841 megawatts
occurred on January 13, 1997.
Construction Program
Total gross property additions (including construction work in
progress) for the three years ended December 31, 1998, amounted to
$168.1 million, and retirements during the same period amounted to
$11.5 million.
The Company's total construction-related expenditures,
including allowance for funds used during construction ("AFUDC"),
were $50.9 million in 1998 and for the next three years are
estimated for planning purposes to be as follows:
Estimated Construction Expenditures
(amounts in millions)
1999 2000 2001 Total
New generating facilities 25.7 41.9 21.6 89.2
Additions to existing 11.7 17.5 12.5 41.7
generating facilities
Transmission facilities 5.3 15.0 8.0 28.3
Distribution system additions 18.0 22.1 22.6 62.7
General and other additions 3.9 2.3 1.8 8.0
Total $ 64.6 $ 98.8 $ 66.5 $229.9
The Company's projected construction plans include
expenditures for the 350-megawatt expansion project at the State
Line Power Plant to be completed in 2001 (the "State Line Project")
at an estimated cost of $185 million (of which $100 million is
expected to be the Company's share). The Company has entered into
a Memorandum of Understanding with Western Resources with respect
to the construction and operation of the State Line Project. This
expansion would consist of adding an additional Westinghouse 501F
combustion turbine, two heat recovery steam generators and a steam
turbine and auxiliary equipment to an already existing 501F
combustion turbine, which would create a nominal 500-megawatt
combined cycle unit. The Company would operate the State Line
Project and would have an undivided 60% joint ownership interest.
Western Resources would have the remaining undivided 40% joint
ownership interest. In addition to the expenditures set forth
above, the Company would transfer to Western Resources at book
value an undivided 40% joint ownership interest in its existing
State Line 501F combustion turbine and the land needed for the
State Line Project. Additions to the Company's 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.
See "- Electric Generating Facilities and Capacity" and Item 7,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources" for
further information about the State Line Project.
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 estimates due to a number
of factors including changes in equipment delivery schedules,
changes in plans with respect to the State Line Project, changes in
customer requirements, construction delays, ability to raise
capital, environmental matters, the extent to which the Company
receives 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 -
Competition."
Fuel
Coal supplied approximately 83.3% of the Company's total fuel
requirements in 1998 based on kilowatt-hours generated. The
remainder was supplied by natural gas (16.5%) with oil generation
being insignificant. In 1997 coal and natural gas supplied
approximately 92.0% and 8.0% respectively. The increased gas usage
is a trend that the Company expects to continue.
The Company's Asbury Plant is fueled primarily by coal with
oil being used as startup fuel. The Plant is currently burning a
coal blend consisting of approximately 90% Western coal and 10%
local coal on a tonnage basis. Under normal conditions, the
Company's targeted coal inventory supply at Asbury is approximately
45 days. As of December 31, 1998, the Company had sufficient coal
on hand to supply anticipated requirements at Asbury for 68 days
due to seven additional train loads of coal the Company had
delivered by an alternative carrier in anticipation of winter coal
needs.
The Company's Riverton Plant fuel requirements are primarily
met by coal with the remainder supplied by natural gas and oil. The
Riverton Plant is currently burning a coal blend consisting of
approximately 80% Western coal and 20% local coal on a tonnage
basis. Under normal conditions, the Company's targeted coal
inventory supply at Riverton is 45 days. As of December 31, 1998,
the Company had coal supplies on hand to meet anticipated
requirements at the Riverton Plant for 36 days.
The Company has a long-term contract, expiring in 2004, with a
subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur
Western coal to meet its requirements for such coal at the Asbury and
Riverton Plants during the term of the contract. This Peabody coal is
supplied from the Rochelle and North Antelope mines located in Campbell
County, Wyoming, and is shipped from there to the Asbury Plant by rail, a
distance of approximately 800 miles. The coal is delivered under a
transportation contract with Western Railroad Properties, Inc., Union
Pacific Railroad Company and The Kansas City Southern Railway Company. The
Company owns one 125-car unit train, which delivers Peabody coal to the
Asbury Plant, and leases additional railcars on an as-needed basis. The
Peabody coal is transported from Asbury to Riverton via truck. Anticipated
requirements for local coal at both Plants are supplied under a coal supply
agreement with the Mackie-Clemens Fuel Company which expires on December
31, 1999.
The Company filed suit against Union Pacific and Kansas City Southern
Railway on August 22, 1997 seeking to void the existing contract and
receive restitution for damages due to nonperformance. This suit was a
result of the coal delivery problems plaguing the industry in past years
that caused the Company's Western coal inventory to fall to a 20-day supply
by the end of 1997. The action is pending.
The Company's Energy Center and State Line combustion turbine
facilities are fueled primarily by natural gas with oil being used as a
backup fuel. The Company's policy is to maintain a supply of oil at these
facilities which would support full load operation for approximately three
days. Based on current and projected fuel prices, it is expected that these
facilities will continue to be operated primarily on natural gas.
The Company has a firm agreement with Williams Natural Gas Company,
expiring December 31, 2011, for the transportation of natural gas to the
Empire Energy Center, the State Line Power Plant or the Riverton Plant, as
elected by the Company. The Company expects that its remaining gas
transportation requirements, as well as the majority of its gas supply
requirements, will be met by spot purchases. The Company historically has
purchased natural gas on a short-term basis.
Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is
jointly-owned by Kansas City Power & Light ("KCPL") (70%), St. Joseph Light
& Power Company ("SJLP") (18%) and the Company (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. The
coal is transported by rail under a contract expiring on December 31, 2000,
with Burlington Northern, Kansas City Southern Railway Company and the
MO-KAN-TEX railroads. The remainder of Iatan Unit No. 1's requirements
for coal are met with 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 the
Company's facilities:
1998 1997 1996
Coal - Iatan $0.857 $0.871 $0.847
Coal - Asbury 1.100 1.088 1.116
Coal - Riverton 1.214 1.235 1.250
Natural Gas 2.495 2.665 2.365
Oil 4.386 4.137 4.437
The Company's weighted cost of fuel burned per kilowatt-hour generated
was 1.570 cents in 1998, 1.397 cents in 1997 and 1.403 cents in 1996. The
increase in the Company's weighted fuel cost reflects increased natural gas
usage in 1998.
Employees
At December 31, 1998, the Company had 626 full-time employees, of whom
330 were members of Local 1474 of The International Brotherhood of
Electrical Workers ("IBEW"). On November 8, 1996, the Company signed a
three-year agreement with the IBEW expiring on October 31, 1999. The
agreement provides, among other things, for a 3.0% increase in wages
commencing on November 1, 1996, with additional minimum increases of 2.75%
at November 1, 1997 and November 1, 1998. The Company expects to begin
negotiations for a new union contract in late summer of 1999.
ELECTRIC OPERATING STATISTICS (1)
1998 1997 1996 1995 1994
Electric Operating Revenues
(000s):
Residential $100,567 $ 88,636 $ 86,014 $ 81,331 $ 71,977
Commercial 71,810 64,940 61,811 58,430 54,052
Industrial 39,805 37,192 35,213 32,637 31,317
Public authorities 5,559 4,995 4,180 3,745 3,509
Wholesale on-system 10,928 9,730 9,482 8,360 8,173
Miscellaneous 4,006 3,341 3,639 3,345 2,393
Total system 232,675 208,834 200,339 187,848 171,421
Wholesale off-system 6,126 5,473 4,595 4,000 5,391
Total electric operating $ 238,801 $ 214,307 $ 204,934 $ 191,848 $ 176,812
revenues
Electricity generated and
purchased (000s of Kwh):
Steam 2,228,103 2,372,914 2,231,062 2,374,021 2,495,055
Hydro 70,631 77,578 62,860 71,302 83,556
Combustion turbine 439,517 211,872 162,679 170,479 51,358
Total generated 2,738,251 2,662,364 2,456,601 2,615,802 2,629,969
Purchased 1,970,348 1,839,833 1,968,898 1,540,816 1,394,470
Total generated and 4,708,599 4,502,197 4,425,499 4,156,618 4,024,439
purchased
Interchange (net) (1,894) 1,018 (1,087) (5,851) 630
Total system input 4,706,705 4,503,215 4,424,412 4,150,767 4,025,069
Maximum hourly system 916,000 876,000 842,000 815,000 741,000
demand (Kw)
Owned capacity (end of 878,000 878,000 724,000 737,000 656,500
period) (Kw)
Annual load factor (%) 55.72 55.38 56.85 55.15 57.32
Electric sales (000s of Kwh):
Residential 1,548,630 1,429,787 1,440,512 1,350,340 1,264,721
Commercial 1,246,323 1,171,848 1,154,879 1,086,894 1,018,052
Industrial 960,783 943,287 923,730 859,017 827,067
Public authorities 98,675 101,122 95,652 90,543 86,463
Wholesale on-system 299,256 273,035 262,330 243,869 234,228
Total system 4,153,667 3,919,079 3,877,103 3,630,663 3,430,531
Wholesale off-system 235,391 253,060 219,814 213,590 304,554
Total electric sales 4,389,058 4,172,139 4,096,917 3,844,253 3,735,085
Company use (000s of Kwh) 8,940 9,688 9,584 9,559 9,260
Lost and unaccounted for 308,707 321,38 8 317,911 296,955 280,724
(000s of Kwh)
Total system input 4,706,705 4,503,215 4,424,412 4,150,767 4,025,069
Customers (average number
of monthly bills rendered):
Residential 119,265 117,271 115,116 112,605 109,032
Commercial 21,774 21,323 20,758 20,098 19,175
Industrial 354 346 346 339 318
Public authorities 1,739 1,720 1,696 1,637 1,558
Wholesale on-system 7 7 7 7 7
Total system 143,139 140,667 137,923 134,686 130,090
Wholesale off-system 6 7 9 6 6
Total 143,145 140,674 137,932 134,692 130,096
Average annual sales per 12,985 12,192 12,514 11,992 11,600
residential customer (Kwh)
Average annual revenue per $843.22 $755.82 $747.19 $722.27 $660.14
residential customer
Average residential revenue 6.49c 6.20c 5.97c 6.02c 5.69c
per Kwh
Average commercial revenue 5.76c 5.54c 5.35c 5.38c 5.31c
per Kwh
Average industrial revenue 4.14c 3.94c 3.81c 3.80c 3.79c
per Kwh
<footnote>
(1) See Item 8 - Financial Statements and Supplementary Data for
additional financial information regarding the Company.
Executive Officers and Other Officers of the Registrant
The names of the officers of the Company, their ages and years
of service with the Company as of December 31, 1998, positions held
and effective date of such positions are presented below. Each of
the executive officers of the Company has held executive officer or
management positions within the Company for at least the last five
years.
Age at With the Officer
Name 12/31/98 Positions with the Company Company since since
M.W.McKinney 54 President and Chief Executive Officer 1967 1982
(1997), Executive Vice President -
Commercial Operations (1995),
Executive Vice President (1994),
Vice President - Customer Services
(1982), Director (1991)
V.E. Brill 57 Vice President - Energy Supply (1995) 1962 1975
Vice President - Finance (1983),
Director (1989)
R.B. Fancher 58 Vice President - Finance (1995), Vice 1972 1984
President - Corporate Services (1984)
C.A. Stark 54 Vice President - General Services (1995) 1980 1995
Director of Corporate Planning (1988)
W.L. Gipson 41 Vice President - Commercial Operations 1981 1997
(1997), General Manager (1997),
Director of Commercial Operations (1995),
Economic Development Manager (1987)
D.W. Gibson 52 Director of Financial Services and 1979 1991
Assistant Secretary (1991)
G.A. Knapp 47 Controller and Assistant Treasurer 1978 1983
(1983)
J.S. Watson 46 Secretary-Treasurer (1995), 1994 1995
Accounting Staff Specialist (1994)
Regulation
General. The Company, as a public utility, is subject to the
jurisdiction of the Missouri Public Service Commission ("Missouri
Commission"), the State Corporation Commission of the State of
Kansas ("Kansas Commission"), the Corporation Commission of
Oklahoma ("Oklahoma Commission") and the Arkansas Public Service
Commission ("Arkansas 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. The
Company's transmission and sale at wholesale of electric energy in
interstate commerce and its facilities are also subject to the
jurisdiction of the Federal Energy Regulatory Commission ("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 of FERC Orders
888 and 889 in Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Competition."
The Company's Ozark Beach Hydroelectric Plant is operated
under a license from FERC. See Item 2, "Properties - Electric
Facilities." The Company is disputing a Headwater Benefits
Determination Report it received from FERC on September 9, 1991.
The report calculates an assessment to the Company 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 annual assessment thereafter of $42,914 for the years 1991
through 2011. The Company believes that the methodology used in
making the assessment was incorrect and is contesting the
determination. As of December 31, 1998, FERC had not responded to
the comments filed by the Company on July 31, 1992. The Company is
currently accruing an amount monthly equal to what it believes the
correct assessment to be.
During 1998, approximately 93% of the Company's 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 7% of the Company's electric operating revenues
during 1998.
Rates. See Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Operating Revenues
and Kilowatt-Hour Sales" 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. Fuel adjustment clauses are not
permitted under Missouri law. Pursuant to an agreement with the
Kansas Commission, entered into in connection with a 1989 rate
proceeding, a fuel adjustment clause is not applicable to the
Company's retail electric sales in Kansas. Automatic fuel
adjustment clauses are presently applicable to retail electric
sales in Oklahoma and system wholesale kilowatt-hour sales under
FERC jurisdiction. Arkansas has implemented an Energy Cost Recovery
Rider that replaces the previous fuel adjustment clause. This
rider is adjusted for changing fuel and purchased power costs on an
annual basis rather than the monthly adjustment used by the
previous fuel adjustment clause. Any increases in fuel costs may
be recovered in Missouri and Kansas only through rate filings made
with the appropriate Commissions.
Environmental Matters
The Company is subject to various federal, state, and local
laws and regulations with respect to air and water quality as well
as other environmental matters. The Company believes that its
operations are in compliance with present laws and regulations.
Air. The 1990 Amendments to the Clean Air Act ("1990
Amendments") affect the Asbury, Riverton, and Iatan Power Plants.
Under the 1990 Amendments, each of these plants was designated as
either a Phase I or Phase II facility, dictating when each such
plant would become an "affected unit" for purposes of sulfur
dioxide ("SO2") and nitrogen oxide ("NOx"). The Company, however,
has the option to elect to make a particular plant an affected unit
for either SO2 or NOx at an earlier date. When a plant becomes an
affected unit for a particular emission, it locks in the then
current emission standards. The Asbury Plant is a Phase I facility
that became an affected unit for SO2 under the 1990 Amendments on
January 1, 1995. The Asbury Power Plant will become an affected
unit for NOx on January 1, 2000. The Riverton Plant is classified
as a Phase II facility, meaning it would not become an affected
unit for SO2 or NOx until January 1, 2000. However, the Company
elected to make Riverton an affected unit for NOx in November 1996,
locking in the then current NOx emission standards of .50 and .45
parts per million btu's burned for the respective units. The
Riverton Plant will become an affected unit for SO2 on January 1,
2000. The Iatan Plant is classified as a Phase II facility, which
will become an affected unit for both SO2 and NOx on January 1,
2000.
SO2 Emissions. Under the 1990 Amendments, the amount of SO2
an affected unit can emit is regulated. Each 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 (the "EPA"), withholds annually a percentage of
the emission allowances awarded to each affected unit and sells
those emission allowances through a direct auction. The Company
receives compensation from the EPA for the sale of these
allowances.
In 1998, the Asbury Plant used approximately 52% of its
available SO2 emission allowances. In the year 2000, the number of
SO2 emission allowances that the Asbury Plant will receive each
year is expected to decline by approximately one-half (before EPA
withholding) and the Company anticipates (based on current
operations) that the Plant will use slightly more allowances than
the number available to it, in which case allowances would have to
be supplied by the Company or purchased on the open-market.
When the Iatan Unit becomes an affected unit with respect to
SO2 in 2000, it is expected to be deficient in allowances by a
margin of approximately 25% based on current operating conditions.
Any needed allowances will be supplied by the respective owners
from present inventories or by open-market purchases.
The Riverton Plant's level of emissions will require
significantly more allowances than the number awarded to the Plant
when the facility becomes an affected unit for SO2 in 2000. The
Company is evaluating various methods to achieve compliance with
these requirements including using any available allowances from
the Asbury plant, purchasing allowances from other sources,
modifying certain equipment to permit the use of greater
percentages of low sulfur coal, increasing the use of natural gas
as a fuel at the Plant and purchasing additional power.
NOx Emissions. The EPA has established the NOx emission limit
for cyclone boilers, like the Asbury Power Plant, at 0.86 lbs/MMBTU
effective on January 1, 2000. The Company is currently installing
NOx control modifications that will reduce NOx emissions to meet
these new requirements. The Company estimates the cost of such
compliance to be approximately $0.85 million. The Iatan Plant and
the Riverton Plant as currently operated are each in compliance
with the NOx limits applicable to them under the 1990 Amendments.
In September 1998, the EPA issued a final NOx State
Implementation Plan call ("the SIP Call") to address the regional
transport of ground-level ozone, the main component of smog. When
emitted, NOx reacts with volatile organic chemicals in the presence
of sunlight to form ground level ozone. The rule requires the
District of Columbia and 22 Midwestern and Eastern states,
including the entire state of Missouri (but excluding Kansas,
Arkansas and Oklahoma), to reduce NOx emissions up to 85% below the
levels established by the 1990 Amendments. State Implementation
Plans ("SIPs") for the reduction of smog-causing emissions of NOx
must be submitted by the States to the EPA in September 1999. The
Missouri Department of Natural Resources ("MDNR") is developing its
SIP for review by the EPA.
The Asbury, State Line, Energy Center and Iatan Power Plants
are affected by this SIP Call. If unchanged, this SIP Call would
require installation of additional NOx control equipment at the
Asbury and Iatan Power Plants by April 1, 2003 and the possible
purchase of NOx credits for the Energy Center and State Line Power
Plants. The Company is proceeding with the development of
compliance plans, including cost determination. The EPA SIP Call
also establishes a Federal NOx Trading Program similar to the SO2
allowance trading system described above. Allowance needs for the
Asbury, State Line and Energy Center Plants cannot be determined
until the MDNR SIP is developed and approved by the EPA.
The Company has joined two litigations running concurrently in
the Washington D.C. Circuit Court against the EPA SIP Call. One
suit has been filed by the Midwest Ozone Group and another by an
alliance of western Missouri utilities. A request for an expedited
review of the cases has been granted. However, the Company does
not expect to have a decision before April 2000. If the litigation
is unsuccessful, the Company will be required to install additional
NOx control equipment at the Asbury Power Plant at an estimated
capital cost of approximately $16 million and which will take
approximately three years to complete. This equipment would result
in additional operating costs of approximately $2.5 - $5 million
annually. Such estimated capital cost is not currently included in
the Company's construction budget.
Water. The Company operates 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 Asbury permit is
under review at the present time and should be issued in Spring
1999.
Other. Under Title 5 of the 1990 Amendments, the Company
must obtain site operating permits for each of its 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. The Company
submitted applications for these permits in 1997 in accordance with
the 1990 Amendments and have received final permits for the Energy
Center and State Line Power Plants. The Company has received the
draft permit for Asbury and expects the final permit to be issued
by mid-1999. The Riverton Permit application is under review by
the Kansas Department of Health and Environment.
Conditions Respecting Financing
The Company's Indenture of Mortgage and Deed of Trust, dated
as of September 1, 1944, as amended and supplemented (the
"Mortgage"), and its Restated Articles of Incorporation (the
"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
generally permits the issuance of additional bonds only if net
earnings (as defined) for a specified twelve-month period are at
least twice the annual interest requirements on all bonds at the
time outstanding, including the additional issue and all
indebtedness of prior rank. Under this test, on December 31, 1998,
the Company could have issued under the Mortgage approximately
$205.5 million principal amount of additional bonds (at an assumed
interest rate of 6.50%). 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, 1998, the Company had retired bonds and
net property additions which would enable the issuance of at least
$112.5 million principal amount of bonds.
Under the Restated Articles, (a) additional cumulative
preferred stock may be issued only if net income of the Company
available for interest and dividends (as defined) 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, and (b)
the amount of unsecured indebtedness outstanding may not exceed 20%
of the sum of the outstanding secured indebtedness plus the capital
and surplus of the Company. Under these restrictions, based on the
twelve months ended December 31, 1998, the Company could issue
shares of cumulative preferred stock with an aggregate par value of
approximately $136.0 million (8-1/8% dividend rate assumed) and at
December 31, 1998, the Company could incur maximum unsecured
indebtedness of approximately $101.5 million.
ITEM 2. PROPERTIES
Electric Facilities
At December 31, 1998, the Company owned generating facilities
(including its interest in Iatan Unit No. 1) with an aggregate
generating capacity of 878 megawatts.
The principal electric generating plant of the Company 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 24% of the Company's owned generating
capacity and in 1998 accounted for approximately 43% of the energy
generated by the Company and 25% of the total energy sold by the
Company. 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
was in 1996 and the next such extended outage will occur in 2001.
See Item 7 for additional information concerning the maintenance
outage. The Unit No. 2 turbine is inspected approximately every
35,000 hours of operations. The unit can be overhauled without
Unit No. 1 having to come off-line. When the Asbury Plant is out of
service, the Company typically experiences increased purchased
power and fuel costs associated with replacement energy. See Item
1 "Business - Regulation - Fuel Adjustment Clauses," for additional
information concerning increased purchased power and fuel costs.
The Company's 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. The
five-year scheduled maintenance outage for the Riverton Plant
occurred during the second quarter of 1998.
The Company owns 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. The
Company is entitled to 12% of the unit's available capacity and is
obligated to pay for that percentage of the operating costs of the
Unit. KCPL and SJLP own 70% and 18%, respectively, of the Unit.
KCPL operates the unit for the joint owners. See Note 9 of "Notes
to Financial Statements" under Item 8.
The Company also has two combustion turbine peaking units at
the Empire Energy Center in Jasper County, Missouri, with an
aggregate generating capacity of 180 megawatts. These peaking
units operate on natural gas as well as oil.
The Company's State Line Power Plant, which is located west of
Joplin, Missouri, consists of two combustion turbine units with an
aggregate generating capacity of 253 megawatts. These units burn
natural gas as a primary fuel and have the capability of burning
oil. Unit No. 1 was placed in service in mid-1995 and Unit No. 2
was placed in service in mid-1997. Reference is made to Item 1
"Business - Electric Generating Facilities and Capacity" and Item 1
"Business - Construction Program" for information with respect to
the plans for expansion of the generating capacity at the State
Line Power Plant. Upon commercial operation of the State Line
Project, the Company would have generating capacity of 101
megawatts from State Line Unit No. 1 and 300 megawatts (60% of 500)
from the combined cycle unit, resulting in an aggregate capacity of
401 megawatts.
The Company's hydroelectric generating plant, located on the
White River at Ozark Beach, Missouri, has a generating capacity of
16 megawatts, subject to river flow. The Company has a long-term
license from FERC to operate this plant which forms Lake Taneycomo
in Southwestern Missouri.
At December 31, 1998, the Company's transmission system
consisted of approximately 22 miles of 345 kV lines, 412 miles of
161 kV lines, 756 miles of 69 kV lines and 81 miles of 34.5 kV
lines. Its distribution system consisted of approximately 6,104
miles of line.
The electric generation stations owned by the Company are
located on land owned in fee. The Company owns a 3% undivided
interest as tenant in common with KCPL and SJLP in the land for the
Iatan Generating Station. Substantially all the electric
transmission and distribution facilities of the Company 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
property, plant and equipment of the Company are subject to the
Mortgage.
Water Facilities
The Company also owns and operates water pumping facilities
and distribution systems consisting of a total of approximately 78
miles of water mains in three communities in Missouri.
ITEM 3. LEGAL PROCEEDINGS
No legal proceedings required to be disclosed by this Item are
pending.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's common stock is listed on the New York Stock
Exchange. On March 1, 1999, there were 9,040 record holders of its
common stock. The high and low sale prices for its common stock
reported in The Wall Street Journal as New York Stock Exchange
composite transactions, and the amount per share of quarterly
dividends declared and paid on the common stock for each quarter of
1998 and 1997 were as follows:
Price of Common Stock Dividends Paid
1998 1997 Per Share
High Low High Low 1998 1997
First Quarter $22.500 $18.375 $19.250 $17.750 $0.32 $0.32
Second Quarter 22.500 20.000 18.375 16.000 0.32 0.32
Third Quarter 23.375 19.313 18.250 16.250 0.32 0.32
Fourth Quarter 26.125 20.875 19.938 17.313 0.32 0.32
Holders of the Company's common stock are entitled to
dividends if, as, and when declared by the Board of Directors of
the Company, out of funds legally available therefor, subject to
the prior rights of holders of the Company's outstanding cumulative
preferred stock and any 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 the Company may not declare or
pay any dividends (other than dividends payable in shares of its
common stock) or make any other distribution on, or purchase (other
than with the proceeds of additional common stock financing) any
shares of, its 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) accumulated subsequent to August 31, 1944, or
the date of succession in the event that another corporation
succeeds to the rights and liabilities of the Company by a merger
or consolidation. As of December 31, 1998, said dividend
restriction did not affect any of the retained earnings of the
Company.
The Company's Dividend Reinvestment and Stock Purchase Plan
(the "Reinvestment Plan") allows common and preferred stockholders
to reinvest dividends of the Company into newly issued shares of
the Company's common stock at 95% of a market price average
calculated pursuant to the Reinvestment Plan. Stockholders may also
purchase, for cash and within specified limits, additional stock at
100% of such market price average. The Company may elect to make
shares purchased in the open market rather than newly issued shares
available for purchase under the Reinvestment Plan. If the Company
so elects, the purchase price to be paid by Reinvestment Plan
participants will be 100% of the cost to the Company of such
shares. Participants in the Reinvestment Plan do not pay
commissions or service charges in connection with purchases under
the Reinvestment Plan.
On August 1, 1998 the Company implemented a new Stock Unit
Plan for Directors. See Note 3 of "Notes to Financial Statements"
under Item 8 for additional information regarding this plan.
During 1998, 34,214 units were granted upon conversion of
previously earned retirement benefits, 1,681 units were granted for
services provided in 1998 and 1,068 units were granted pursuant to
the Reinvestment Plan. Securities issued under the Stock Unit Plan
for Directors will not be registered under the Securities Act of
1933, as amended, pursuant to Section 4(2) thereof.
The Company has a shareholders rights plan which expires July
25, 2000, under which each of its common stockholders has one-half
a 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 the Company's common stock or if certain other
events occur. See Note 4 of "Notes to Financial Statements" under
Item 8 for further information.
The By-laws of the Company 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 the Company's
capital stock.
See Note 3 of "Notes to Financial Statements" under Item 8 for
additional information regarding the Company's common stock.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands, except per share amounts)
1998 1997 1996 1995 1994
Operating revenues $ 239,858 $ 215,311 $ 205,984 $ 192,838 $ 177,757
Operating income $ 47,372 $ 40,962 $ 36,652 $ 33,151 $ 32,005
Total allowance for funds $ 409 $ 1,226 $ 1,420 $ 2,239 $ 1,715
used during construction
Net income $ 28,323 $ 23,793 $ 22,049 $ 19,798 $ 19,683
(1)
Earnings applicable to $ 25,912 $ 21,377 $ 19,633 $ 17,381 $ 18,120
common stock (1)
Weighted average number of
common shares 16,932,704 16,599,269 16,015,858 14,730,902 13,734,231
outstanding
Basic and diluted earnings
per weighted average
shares outstanding $ 1.53 $ 1.29 $ 1.23 $ 1.18(1$ 1.32
Cash dividends per common $ 1.28 $ 1.28 $ 1.28 $ 1.28 $ 1.28
share
Common dividends paid as a
percentage of earnings
applicable to common stock 83.7% 99.4% 104.5% 108.9% 97.0%
common stock
Allowance for funds used
during construction as a
percentage of earnings
applicable to common stock 1.6% 5.7% 7.2% 12.9% 9.5%
Book value per common share
outstanding at end
of year $ 13.40 $ 13.03 $ 12.93 $ 12.67 $ 12.42
Capitalization:
Common equity $ 229,791 $ 219,034 $ 213,091 $ 193,137 $ 173,780
Preferred stock without
mandatory redemption
provisions $ 32,634 $ 32,902 $ 32,902 $ 32,902 $ 32,902
First mortgage bonds $ 246,093 $ 196,385 $ 219,533 $ 194,705 $ 184,977
Ratio of earnings to fixed
charges 3.32 3.01 3.11 2.90 3.16
Ratio of earnings to combined
fixed charges and
preferred stock
dividend requirements 2.78 2.50 2.53 2.36 2.70
Total assets $ 653,294 $ 626,465 $ 596,980 $ 557,368 $ 520,213
Utility plant in service
at original cost $ 831,496 $ 797,839 $ 717,890 $ 682,609 $ 611,360
Utility plant expenditures
during the year $ 47,366 $ 53,280 $ 59,373 $ 49,217 $ 71,649
<footnote>
(1) Reflects a pre-tax charge of $4,583,000 for certain one-time
costs associated with the Company's voluntary early retirement
program.
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 the year ended December 31, 1998,
compared to the year ended December 31, 1997, and for the year
ended December 31, 1997, compared to the year ended December 31,
1996.
Operating Revenues and Kilowatt-Hour Sales
Of the Company's total electric operating revenues during
1998, approximately 42% were from residential customers, 30% from
commercial customers, 17% from industrial customers, 5% from
wholesale on-system customers and 3% from wholesale off-system
transactions. The remainder of such revenues were derived from
miscellaneous sources. The percentage changes from the prior year
in kilowatt-hour ("Kwh") sales and revenue by major customer class
were as follows:
Kwh Sales Revenues
1998 1997 1998 1997
Residential 8.3% (0.7)% 13.5% 3.1%
Commercial 6.4 1.5 10.6 5.1
Industrial 1.9 2.1 7.0 5.6
Wholesale On- 9.6 4.1 12.3 2.6
System
Total System 6.0 1.1 11.3 4.5
Kwh sales for the Company's on-system customers increased
during 1998 primarily due to above-average temperatures during the
second and third quarters. Revenues increased more than the
corresponding increase in Kwh sales primarily due to increased
rates in Missouri and Arkansas as reflected in the table below and
the winter/summer differential in rates. This differential results
from summer rates being higher than winter rates, so warm summer
temperatures that increase summer Kwh usage cause the corresponding
annual revenues to increase at a greater rate. Customer growth
increased slightly to 1.79% in 1998 as compared to 1.68% in 1997.
Residential Kwh sales increased 8.3% while commercial Kwh sales
increased 6.4% as compared to 1997, primarily due to the above-
average temperatures. Industrial classes, although not
particularly weather-sensitive, also showed an increase in Kwh
sales and revenues due to continued increases in business activity
throughout the Company's service territory as well as the Missouri
and Arkansas rate increases.
On-system wholesale Kwh sales were up significantly in 1998,
reflecting the warm summer temperatures and the continued increases
in business activity. Revenues associated with these sales
increased more than the corresponding Kwh sales as a result of the
operation of the fuel adjustment clause applicable to such FERC
regulated sales. This clause permits changes in fuel and purchased
power costs to be passed along to customers without the need for a
rate proceeding.
Kwh sales for the Company's on-system customers increased only
slightly during 1997 due to cool summer weather, while revenues
increased more than the corresponding increase in Kwhs primarily
due to increased rates in Missouri as reflected in the table below.
Customer growth slowed from 2.33% in 1996 to 1.68% in 1997.
Residential Kwh sales decreased slightly compared to 1996 due to a
milder first half of 1997 while revenues for the period increased
because of increases in Missouri rates during the last half of
1997. Commercial and industrial classes showed an increase in Kwh
sales and revenues in 1997 because their sales are not as impacted
by weather. Revenues from the on-system wholesale customers
increased more than the Kwh sales for that class due to the
operation of the fuel adjustment clause.
The following table sets forth information regarding electric
rate increases affecting the revenue comparisons discussed above:
Percent
Date Increase Increase Increase Date
Jurisdiction Requested Requested Granted Granted Effective
Arkansas 02-19-98 $ 618,497 $ 358,848 6.60% 08-24-98
Missouri 08-30-96 23,438,000 13,589,364 8.25% *
<footnote>
* An increase of $10,589,364 was granted effective 07-28-97.
An additional $3,000,000 increase became effective 09-19-97.
The Company's future revenues from the sale of electricity
will continue to be affected by economic conditions, business
activities, competition, deregulation of the energy industry,
weather, regulation, changes in electric rate levels and changing
patterns of electric energy use by customers. Inflation affects the
Company's operations in that historical costs rather than current
replacement costs are recovered in the Company's rates.
Off-System Transactions
In addition to sales to its own customers, the Company sells
power to other utilities to the extent it is available and provides
transmission service through its system for transactions between
other energy suppliers. During 1998 revenues from such off-system
transactions were approximately $8.3 million as compared to
approximately $7.6 million during 1997 and approximately $6.3
during 1996. The margin on such off-system sales is lower than on
sales to the Company's on-system customers. In addition, pursuant
to an order issued by the FERC and subsequent tariffs filed by the
Company and SPP, these off-system sales have been opened up to
competition. The Company cannot predict, however, the effect such
competition will have on its future operations or financial
results. See "- Competition" below for more information on these
open-access tariffs.
Operating Revenue Deductions
During 1998, total operating expenses increased approximately
$7.5 million (6.6%) compared to the prior year. Total fuel costs
were up approximately $5.8 million (16.0%) due primarily to the
increased generation from higher-cost gas-fired combustion turbine
units at both State Line and the Energy Center. This increased
generation was due to increased customer demand in the second and
third quarters of 1998 resulting from the warmer temperatures.
Increased gas usage is a trend the Company expects to continue,
especially when the State Line Project begins commercial operation.
Natural gas prices were lower by 3.0% during 1998 as compared to
1997, helping to offset some of the increased fuel expense. Total
purchased power costs increased slightly by approximately $0.4
million (0.9%) during 1998.
Other operating expenses increased approximately $1.3 million
(4.3%) during 1998, compared to 1997, due primarily to increases in
customer accounts expense and administrative and general expense.
Approximately $0.7 million of this increase was a one-time charge
due to the initiation of the Directors Stock Unit Plan, a stock-
based retirement compensation program for the Company's Directors.
Maintenance and repairs expense increased approximately $4.7
million (36.4%) during 1998. Scheduled maintenance resulting from
increased usage of the gas-fired combustion turbines at the Energy
Center and the State Line Power Plant accounted for approximately
$2.8 million of this increase while approximately $1.1 million
resulted from the first quarter spring maintenance outage at the
Asbury Plant and the second quarter five-year scheduled maintenance
outage at the Riverton Plant. Transmission and distribution system
maintenance contributed $0.8 million to the increase. Maintenance
and repair expense is expected to increase significantly in the
first quarter of 1999 as a result of a New Year's Day ice storm
that interrupted service to approximately 35,000 of the Company's
Missouri and Kansas customers over a three day period.
Depreciation and amortization expense increased approximately
$1.6 million (6.8%) during 1998, compared to 1997, due to increased
levels of plant and equipment placed in service. Total income
taxes increased approximately $3.2 million (24.5%) during 1998 due
primarily to higher taxable income during the current year. See
Note 8 of "Notes to Financial Statements" for additional
information regarding income taxes. Other taxes were up
approximately $1.2 million (10.3%) during the year largely as a
result of increased property taxes and city franchise taxes.
During 1997, total operating expenses increased approximately
$2.9 million (2.6%) compared to the prior year. Total fuel costs
were up approximately $2.5 million (7.6%) during 1997, due
primarily to increased generation from higher-cost gas-fired
combustion turbine units at both State Line and the Energy Center.
This increased generation was due to increased customer demand in
the third and fourth quarters of 1997, as well as decreased energy
availability in the SPP during the month of October. Natural gas
prices were also higher by 7.8% during 1997 than in 1996.
Total purchased power costs decreased slightly during 1997,
due primarily to increased usage of the Company's own generation
facilities. Unit No. 2 at the State Line Power Plant was placed in
commercial operation on June 18, 1997, and added 152 megawatts of
capability. Although Asbury underwent an extended five-week spring
outage in 1997, the plant was back on line ahead of schedule and
went on to record a new continuous run record of 170 days and a
record availability rate of 88.5 %.
Other operating expenses increased during 1997, compared to
1996, due primarily to an increase in production expenses related
to the extended Asbury Plant outage in the spring of 1997.
Maintenance and repairs expense decreased during 1997 as a result
of decreased levels of distribution system maintenance.
Depreciation and amortization expense increased due to increased
levels of plant and equipment placed in service during 1997,
particularly Unit No. 2 at the State Line Power Plant. Total
income taxes increased due to higher taxable income. Other taxes
decreased slightly during the year.
Nonoperating Items
Total allowance for funds used during construction ("AFUDC")
amounted to approximately 1.6% of earnings applicable to common
stock during 1998, 5.7% during 1997, and 7.2% during 1996. AFUDC
decreased significantly during 1998 as well as 1997, reflecting
lower levels of construction work in progress, particularly due to
the completion of State Line Unit No. 2.
Interest charges on first mortgage bonds increased $1.3
million (7.7%) compared to the prior year due to the issuance of
$50 million of the Company's First Mortgage Bonds in April, 1998.
These proceeds were used to repay $23 million of the Company's
First Mortgage Bonds due May 1, 1998 and to repay short-term
indebtedness, including that incurred in connection with the
Company's construction program. As a result, commercial paper
interest decreased $0.5 million (42.3%) during the year due to
decreased usage of short-term debt for financing purposes, while
interest income increased, reflecting the higher balances of cash
available for investment.
Other-net deductions increased approximately $0.4 million
during 1998, compared to 1997, due primarily to one-time startup
costs for the Company's non-regulated ventures, such as home
security and fiber optics leasing.
Earnings
Basic and diluted earnings per weighted average share of
common stock were $1.53 during 1998 compared to $1.29 in 1997.
Increased revenue resulted mainly from the unusually warm second
and third quarters of 1998. The 1998 Arkansas rate increase and
the 1997 Missouri rate increases also favorably impacted the
Company's operating results in 1998, as the Missouri jurisdiction
accounts for approximately 90% of the on-system retail sales of the
Company.
Earnings per share of Common stock were $1.29 during 1997
compared to $1.23 in 1996. Increased revenue, resulting mainly
from the increase in Missouri rates in 1997, was partially offset
by a cool summer and fairly mild winter as well as increases in
fuel costs and decreased levels of AFUDC.
Competition
Federal regulation, such as The National Energy Policy Act of
1992 (the "Energy Act") has promoted and is expected to continue to
promote competition in the electric utility industry. The Energy
Act, among other things, eases restrictions on independent power
producers, delegates authority to the FERC to order wholesale
wheeling and grants individual states the power to order retail
wheeling. At this time, Oklahoma is the only state in which the
Company operates that has taken any such action. In Missouri, the
Joint Committee of the Missouri legislature received testimony
during 1997 and 1998 but there was no legislative action taken. In
Kansas, although different bills were introduced into the House and
Senate during 1997, no legislative action was taken in 1997 or in
1998. Discussions regarding deregulation, however, are expected to
continue in Missouri and Kansas throughout 1999. In Oklahoma, the
Electric Restructuring Act of 1997 was passed by the Legislature
and signed into law by the Governor. The bill, with a target date
of July 1, 2002, was designed to provide for the orderly
restructuring of the electric utility industry in the state and
move the state toward open competition for electric generation. In
Arkansas, the House and Senate passed a concurrent resolution in
1997 requesting a study of the impact of competition on the
electric utility industry. Legislation has been introduced in
Arkansas with a target date of 2002.
In April 1996, the FERC issued Order No. 888 (the "Order")
which requires all electric utilities that own, operate, or control
interstate transmission facilities to file open access tariffs that
offer all wholesale buyers and sellers of electricity the same
transmission services that they provide themselves. The utility
would have to take service under those tariffs for its own
wholesale power transactions. The Order requires a functional
unbundling of transmission and power marketing services. The Order
also provides stranded cost recovery mechanisms for utilities to
recover costs that were incurred to serve wholesale customers that
would no longer be recoverable as a result of the customer
departing the system and obtaining electric service from another
supplier.
In accordance with the Order, on July 9, 1996, the Company
filed its open access transmission tariff (the "Company Tariff")
with the FERC. Following an extensive audit and discussions, the
Company, the FERC and intervenors reached a settlement on August 1,
1997. The rates submitted with the settlement, applicable to
customers who did not have service agreements in effect, were made
effective as of July 9, 1996. For customers with service
agreements in effect, the Company Tariff will not be applicable
until a rate increase has been filed, which may not be made prior
to June 1999.
On December 19, 1997, the SPP filed its own open access
transmission tariff (the "Regional Tariff") on behalf of its
members to provide pool-wide, short-term transmission services
using pricing which is based on distance. As of June 1, 1998, the
date the FERC declared the Regional Tariff effective, the SPP began
providing short-term firm and non-firm point-to-point transmission
services for periods of less than one year under this tariff. The
SPP, on December 1, 1998, filed proposed revisions to the Regional
Tariff that included the addition of long-term point-to-point
transmission service as a service offered under the Regional Tariff
(along with a few other minor changes). The FERC accepted the
amended tariff, making it effective January 30, 1999 as to minor
changes and effective April 1, 1999 as to the inclusion of the long-
term transmission services. A transmission customer taking long-
term firm point-to-point transmission service through or out of the
SPP, will pay one charge for service. That rate, if the load
originates outside the SPP, will be a single system-wide rate based
on the weighted average rate of each SPP member's zone through
which the load passes. The rate for each zone is based on such
member's rate for long-term firm service under its individual open
access tariffs. In addition, if the load originates in a
particular member's zone, then the system-wide rate will be based
solely on such member's rate under its own tariff. Rates for short-
term transmission services are computed much the same way as for
long-term transmission services, except that the rates may be
discounted by the SPP or a particular member, as appropriate.
The Regional Tariff, as amended, applies to many of the
transmission services for which the Company Tariff was designed.
Where that is the case, the Company will have to share revenues
received from such transmission services with other members of the
SPP based on a megawatt mile method of calculating transmission
service charges. However, the Company Tariff will apply instead of
the Regional Tariff to, and the Company will receive 100% of the
revenues from, (1) all transmission services for which the load
originates within the Company's zone and does not pass through the
zone of any other member of the SPP and (2) all long-term firm
point-to-point transmission services provided by the Company
pursuant to contracts entered into prior to April 1, 1999. The
availability of purchased power in the bulk power market,
generation fuel costs and the requirements of other electric
systems are all factors that affect the amount of power purchased
and wheeled through the Company's and the SPP's transmission system
each year. As a result, the Company cannot predict the effect of
these tariffs on its future operations or financial results due to
its inability to predict these factors.
Several factors exist which may enhance the Company's ability
to compete as deregulation occurs. The Company is able to generate
and purchase power relatively inexpensively; during 1998, the
Company's retail rates were approximately 30% less than the
electric industry average. In addition, less than 5% of the
Company's electric operating revenues are derived from sales to on-
system wholesale customers, the type of customer for which the FERC
is already requiring open access. At the same time, the Company
could face increased competitive pressure as a result of its
reliance on relatively large amounts of purchased power and its
extensive interconnections with neighboring utilities. The Company
cannot predict, however, the ultimate effect competition or
regulatory change will have on its future operations or financial
results, but such effects may be material.
LIQUIDITY AND CAPITAL RESOURCES
The Company's construction-related expenditures totaled
approximately $51.9 million, $56.7 million, and $62.3 million in
1998, 1997 and 1996, respectively. Approximately $10.8 million of
construction expenditures during 1998 were related to the State
Line Power Plant including advance payments on the new construction
planned in connection with the State Line Project and remaining
payments related to the construction of Unit No. 2 at the State
Line Power Plant, which was placed in service in mid-1997.
Additions to the Company's transmission and distribution systems to
accommodate customer growth represented approximately $25.5 million
of construction expenditures during 1998. Approximately $3.5
million of the above-mentioned construction expenditures for 1998
is related to the Company's investment in fiber optics cable and
equipment which the Company plans to utilize and to lease to other
entities. Approximately 65% of construction expenditures and other
funds requirements for 1998 were satisfied internally from
operations.
The Company estimates that its construction expenditures will
total approximately $64.6 million in 1999, $98.8 million in 2000
and $66.5 million in 2001. Of these amounts, the Company
anticipates that it will spend $18.0 million, $22.1 million and
$22.6 million in 1999, 2000 and 2001, respectively, for additions
to the Company's distribution system to meet projected increases in
customer demand. These construction expenditure estimates also
include approximately $25.7 million, $41.9 million and $21.6
million in 1999, 2000 and 2001 respectively, for the construction
of new generating facilities as part of the State Line Project
discussed in the following paragraph.
The Company announced on October 2, 1998 its plans for the
construction of a 350-megawatt addition to the State Line Power
Plant. This State Line Project would consist of an additional
combustion turbine, two heat recovery steam generators and a steam
turbine and auxiliary equipment. It is estimated that construction
would begin in the fall of 1999 and that the State Line Project
would be operational by June 2001. The Company announced on
February 4, 1999 that it had entered into a Memorandum of
Understanding which contemplates entering into a joint ownership
agreement under which the Company would own an undivided 60%
interest in the State Line Project with Western Resources owning
the remainder. The Company would also be entitled to 60% of the
capacity of the State Line Project. The Company would contribute
its existing 152-megawatt State Line Unit No. 2 combustion turbine
to the State Line Project, and as a result, upon commercial
operation, the State Line Project would provide the Company with
150 megawatts of additional capacity. The total cost of the State
Line Project is estimated to be $185 million (of which $100 million
is expected to be the Company's share).
The Company estimates that internally generated funds will
provide approximately 40% of the funds required between 1999 and
2001 for estimated construction expenditures. As in the past, in
order to finance the additional amounts needed for such
construction, the Company intends to utilize short-term debt and
sales of public offerings of long-term debt or equity securities,
including the sale of the Company's common stock pursuant to its
Dividend Reinvestment Plan and Employee Stock Purchase Plan as well
as internally-generated funds. The Company will continue to utilize
short-term debt as needed to support normal operations or other
temporary requirements. See Note 5 of "Notes to Financial
Statements" regarding the Company's line of credit.
On April 28, 1998, the Company sold to the public in an
underwritten offering $50 million aggregate principal amount of its
First Mortgage Bonds, 6 1/2% Series due 2010. The net proceeds from
this sale were added to the Company's general funds and were used
to repay $23 million of the Company's First Mortgage Bonds, 5.70%
Series due May 1, 1998 and to repay short-term indebtedness,
including indebtedness incurred in connection with the Company's
construction program.
As of December 31, 1998, the Company's ratings for its first
mortgage bonds, preferred stock and commercial paper were as
follows:
Duff & Phelps Moody's Standard & Poor's
First Mortgage Bonds A+ A2 A-
Preferred Stock A a3 BBB
Commercial Paper D-1 P-1 A-2
YEAR 2000
Year 2000 Background
Many existing computer programs use only two digits to
identify a year in the date field. These programs were designed
and developed without considering the impact of the upcoming
century change. As a result, computer systems may fail completely
or produce erroneous results unless corrective measures are taken.
The Company is engaged in an on-going project to identify, evaluate
and implement changes to both information technology ("IT") and non-
IT systems in order to achieve Year 2000 readiness. The Company
has also become a member of the Edison Electric Institute's Year
2000 Committee and the Electric Power Research Institute's Y2K
Embedded Systems Program in order to assist in the implementation
of its Year 2000 Readiness Plan. In addition, the Company is
participating in the North American Electric Reliability Council's
("NERC") efforts to prepare mission critical systems for Year 2000
readiness. NERC's target is to have all mission critical electric
power production, transmission, and delivery systems Year 2000
ready by June 30, 1999. The Company is working within that
framework and plans to participate in two industry-wide Year 2000
drills on April 9,1999 and September 9, 1999.
The Company is using a multi-step approach in achieving its
Year 2000 Readiness Plan. These steps include creating awareness
of the Year 2000 problem, forming a Year 2000 task force,
developing procedures for documenting Year 2000 readiness,
developing a methodology for the Year 2000 Readiness Plan and
testing and remediation of Year 2000 affected items pursuant to the
Year 2000 Readiness Plan. Developing the methodology for the Year
2000 Readiness Plan includes creating and implementing an ongoing
communication program with both internal and external parties,
performing an inventory of possible Year 2000 affected items,
assessing and prioritizing each such inventory item as to level of
criticality, scheduling testing and remediation of such items in
order of criticality, and developing contingency planning. The
management consulting firm of Sargent & Lundy has reviewed the
process involving the implementation of the Year 2000 Readiness
Plan as well as the plan itself. Recommendations based on their
independent findings will be implemented as a step of the Year 2000
Readiness Plan.
The Company has purchased a new financial management software
package from PeopleSoft that is Year 2000 ready. The package
includes systems for general ledger, accounts payable and asset
management; purchasing and inventory; human resources, benefits,
time and labor, and payroll; as well as budgeting and project
tracking. In addition, a new customer information system,
Centurion, is being developed internally which will be Year 2000
ready. Installation of these systems, which are anticipated to
substantially mitigate the Company's Year 2000 exposure, is
expected to be completed during the first half of 1999.
State of Readiness
A task force has been appointed and is charged with
documenting and testing areas of the Company which may be affected
by the Year 2000. The targeted areas include general preparation,
power generation, energy management systems, telecommunications,
substation controls and system protection and business information
systems. Within each of these areas, the task force is examining
the status of IT systems, non-IT systems and third parties such as
vendors, customers and others with whom the Company does business.
The inventory of Year 2000 items was completed in September 1998.
Assessing and prioritizing each item within the Year 2000 inventory
as to the level of criticality was also completed in September
1998. The ongoing testing and remediation of the highest level of
critical items is scheduled to be completed by the end of the
second quarter of 1999. The Year 2000 task force will also develop
contingency plans in the event that unanticipated problems are
encountered. These plans are also scheduled to be completed during
the second quarter of 1999. The Company currently plans to
substantially complete its Year 2000 testing and compliance
projects by the end of the second quarter of 1999.
The status of each of the targeted areas undergoing testing is
as follows:
General Preparation. Scheduled upgrades to the telephone switch
are 50% complete with the final upgrades scheduled to be completed
early in the second quarter of 1999. The testing of other items is
scheduled to be completed by the end of the first quarter of 1999.
Power Generation. The Ozark Beach Plant has completed 100% of the
testing of affected equipment. The testing of affected equipment
at the Riverton Plant is approximately 50% complete and at the
Energy Center Plant is 90% complete. Assessment and inventory are
complete at all plants. Testing for the Asbury and State Line
Plants is underway. All plants intend to have testing of critical
items complete by the end of the first quarter of 1999 except for
items which can only be tested during scheduled plant shutdowns.
All critical items are anticipated to be tested for Year 2000
readiness by the end of the second quarter of 1999.
Energy Management Systems. The Company is in the process of
installing major upgrades to its Energy Management System hardware
and software as a result of Year 2000 related problems observed
during preliminary system testing. These upgrades are anticipated
to be completed by the end of the first quarter of 1999. The
Company has obtained readiness certifications for most of the other
related components and will conduct its own test on components
critical to the operations of the Energy Management System and
other related systems. Year 2000 related testing of these
components is expected to be completed by the end of the second
quarter of 1999.
Telecommunications. The Company has worked with suppliers and
manufacturers to obtain readiness certifications for its various
telecommunications systems and components. The Company plans to
complete the testing of critical systems and components by the end
of the second quarter of 1999.
Substation Controls and System Protection. Testing of transmission
and distribution equipment to date has identified a minor amount of
equipment that will require Year 2000 remediation. That equipment
will be replaced by the end of the second quarter of 1999.
Business Information Systems. As previously stated, the new
financial management software package from PeopleSoft is Year 2000
ready and the new Centurion customer information system, when
completed, is expected to be Year 2000 ready. As a result of the
implementation of the new software packages, several hardware
changes are being required throughout the Company, delaying testing
of the remaining systems. Currently, the testing of these systems
is 10% complete with the target date for the completion of testing
being mid-1999.
Third Parties. The Company is currently in the process of o
btaining readiness certifications from third party vendors for all
of its core applications and operating systems. The Company
expects to complete this process by the end of the first quarter of
1999. All critical applications will be tested, however,
regardless of whether a certification of readiness has been
obtained. In addition, the Company has begun to contact other
third parties with whom the Company does business (such as major
customers, power pools, power suppliers, transmission providers and
telecommunications providers) in order to assess their states of
readiness. This initial contact phase was completed at the end of
1998. The Company is continuing to monitor the progress of these
third parties. The Company is conducting face to face meetings
with its most critical suppliers and its largest customers and is
corresponding in writing with its other suppliers and customers.
Year 2000 Costs
The Company currently estimates that total costs (which
include the costs of the new financial management software package
and the new customer information system) to update all systems for
Year 2000 readiness will be approximately $3.7 million, of which
approximately $2.8 million have been incurred and capitalized as of
December 31, 1998 and $0.3 million have been incurred and expensed.
Of these capitalized costs, $0.5 million were included in the
capital budget. Costs for specific Year 2000 remediation projects
will be charged to expense while costs to replace software for
business purposes other than addressing Year 2000 issues will be
capitalized.
Risk Assessment and Contingency Plans
At this time, the Company believes the most reasonably likely
worst case scenario is that key customers could experience
significant reductions in their power needs due to their own Year
2000 issues, and there could be a temporary disruption of service
to some customers due to cascading disruptions caused by other
entities whose systems are connected to the Company's. The Company
is assessing the risk of this scenario and will be formulating
contingency plans, currently scheduled to be completed during the
second quarter of 1999, to mitigate the potential impact. The
Company's Year 2000 task force has formed a contingency planning
team which will follow guidelines established by the NERC to
formalize a plan with respect to the above worst case scenario and
other contingencies which may develop by the end of the second
quarter of 1999.
The Company's Readiness Plan is designed to provide corrective
action with respect to Year 2000 risks. If the Plan is not
successfully carried out in a timely manner, or if unforeseen
events occur, Year 2000 problems could have a material adverse
impact on the Company. Management does not expect such problems to
have such an effect on its financial position or results of
operations.
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 future plans, objectives,
expectations and events or conditions concerning various matters
such as capital expenditures (including those planned in connection
with the State Line Project), earnings, competition, litigation,
rate and other regulatory matters, liquidity and capital resources,
Year 2000 readiness (including estimated costs, completion dates,
risks and contingency plans) and accounting matters. Actual results
in each case could differ materially from those currently
anticipated in such statements, by reason of factors such as the
cost and availability of purchased power and fuel; electric utility
restructuring, including ongoing state and federal activities;
weather, business and economic conditions; legislation; regulation,
including rate relief and environmental regulation (such as NOx
regulation); competition, including the impact of deregulation on
off-system sales; and other circumstances affecting anticipated
rates, revenues and costs.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Interest Rate Risk. The Company is exposed to changes in
interest rates as a result of significant financing through its
issuance of fixed-rate debt, commercial paper and preferred stock.
The Company manages its interest rate exposure by limiting its
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 4, 5 and 6 of "Notes
to Financial Statements" under Item 8 for further information.
If market interest rates average 1% more in 1999 than in 1998,
the Company's interest expense would increase, and income before
taxes would decrease, by approximately $150,000. This amount has
been determined by considering the impact of the hypothetical
interest rates on the Company's commercial paper balances as of
December 31, 1998. 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
the Company's financial structure.
Commodity Price Risk. The Company is exposed to the impact of
market fluctuations in the price and transportation costs of coal,
natural gas, and electricity and employs established policies and
procedures to manage its risks associated with these market
fluctuations. At this time none of the Company's commodity
purchase or sale contracts meet the definition of financial
instruments.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Accountants
January 26, 1999
To the Board of Directors and Stockholders of
The Empire District Electric Company
In our opinion, the financial statements listed in the index
appearing under Item 14 on page 46 present fairly, in all
material respects, the financial position of The Empire
District Electric Company at December 31, 1998 and 1997, and
the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
These financial statements are the responsibility of the
Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with
generally accepted auditing standards 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 the opinion expressed
above.
PricewaterhouseCoopers LLP
St. Louis, Missouri
January 26, 1999
Balance Sheet
December 31,
1998 1997
Assets
Utility plant, at original cost:
Electric $ 832,484,754 $ 795,880,240
Water 6,398,086 5,824,165
Construction work in progress 16,701,068 8,114,680
855,583,908 809,819,085
Accumulated depreciation 283,337,538 262,834,707
572,246,370 546,984,378
Current assets:
Cash and cash equivalents 2,492,716 2,545,282
Accounts receivable - trade, net 13,645,641 13,270,329
Accrued unbilled revenues 6,218,889 6,047,739
Accounts receivable - other 1,590,536 1,552,998
Fuel, materials and supplies 15,704,678 13,215,068
Prepaid expenses 929,447 1,001,468
40,581,907 37,632,884
Deferred charges:
Regulatory assets 35,999,139 37,472,225
Unamortized debt issuance costs 3,660,800 3,374,780
Other 805,568 1,000,700
40,465,507 41,847,705
Total Assets $ 653,293,784 $ 626,464,967
Capitalization and Liabilities
Common stock, $1 par value, 20,000,000 shares
authorized, 17,108,799 and 16,776,654 shares
issued and outstanding, respectively $ 17,108,799 $ 16,776,654
Capital in excess of par value 156,975,596 150,784,239
Retained earnings 55,706,779 51,472,897
Total common stockholders' equity 229,791,174 219,033,790
Preferred stock 32,634,263 32,901,800
Long-term debt 246,092,905 196,384,541
508,518,342 448,320,131
Current liabilities:
Accounts payable and accrued liabilities 17,096,272 14,862,581
Commercial paper 14,500,000 28,000,000
Customer deposits 3,438,987 3,140,621
Interest accrued 4,113,300 3,509,680
Taxes accrued, including income taxes - 817,045
Current maturities of long-term debt - 23,000,000
39,148,559 73,329,927
Commitments and Contingencies (Note 10)
Noncurrent liabilities and deferred credits:
Regulatory liability 16,400,125 17,540,757
Deferred income taxes 73,760,362 69,344,653
Unamortized investment tax credits 8,391,000 8,971,000
Postretirement benefits other than pensions 4,463,883 4,463,488
Other 2,611,513 4,495,011
105,626,883 104,814,909
Total Capitalization and Liabilities $ 653,293,784 $ 626,464,967
<footnote>
The accompanying notes are an integral part of these financial statements.
Statement of Income
Year ended December 31
1998 1997 1996
Operating revenues:
Electric $ 238,800,831 $ 214,306,599 $ 204,933,622
Water 1,057,460 1,004,245 1,050,337
239,858,291 215,310,844 205,983,959
Operating revenue deductions:
Operating expenses:
Fuel 41,876,064 36,110,575 33,574,335
Purchased power 47,572,541 47,132,885 47,393,029
Other 31,972,081 30,646,485 30,046,147
121,420,686 113,889,945 111,013,511
Maintenance and repairs 17,522,871 12,843,508 13,672,084
Depreciation and amortization 24,980,637 23,395,291 21,589,511
Provision for income taxes 16,190,000 13,000,000 11,800,000
Other taxes 12,372,321 11,219,730 11,256,486
192,486,515 174,348,474 169,331,592
Operating income 47,371,776 40,962,370 36,652,367
Other income and deductions:
Allowance for equity funds used
during construction 8,938 150,524 538,844
Interest income 263,801 130,685 158,369
Other - net (840,557) (453,127) (344,525)
(567,818) (171,918) 352,688
Income before interest charges 46,803,958 40,790,452 37,005,055
Interest charges:
Long-term debt 17,873,833 16,593,042 14,881,564
Allowance for borrowed fundsd
usedduring construction (400,044) (1,075,465) (881,485)
Other 1,006,831 1,479,896 955,769
18,480,620 16,997,473 14,955,848
Net income 28,323,338 23,792,979 22,049,207
Preferred stock dividend 2,411,784 2,416,340 2,416,340
requirements
Net income applicable to $ 25,911,554 $ 21,376,639 $ 19,632,867
common stock
Weighted average number of
common shares outstanding 16,932,704 16,599,269 16,015,858
Basic and diluted earnings per weighted
weighted average share of $ 1.53 $ 1.29 $ 1.23
common stock
Dividends per share of
common stock $ 1.28 $ 1.28 $ 1.28
<footnote>
The accompanying notes are an integral part of these financial statements.
Statement of Common Stockholder's Equity
Year ended December 31,
1998 1997 1996
Common stock, $1 par value:
Balance, beginning of year $ 16,776,654 $ 16,436,559 $ 15,215,933
Stock/stock units issued through:
Public offering - - 880,000
Dividend reinvestment and stock
purchase plan 259,267 299,134 301,500
Employee benefit plans 35,915 40,961 39,126
Director retirement plan 36,963 - -
Balance, end of year $ 17,108,799 $ 16,776,654 $ 16,436,559
Capital in excess of par value:
Balance, beginning of year $ 150,784,239 $ 145,313,610 $ 125,690,842
Excess of net proceeds over
par value of stock issued:
Public offering - - 14,850,000
Stock plans 6,188,030 5,470,404 5,494,007
Expenses related to common
stock issuance - - (787,580)
Installments received on common
stock/stock purchase, net 3,327 225 66,341
Balance, end of year $ 156,975,596 150,784,239 $ 145,313,610
Retained earnings:
Balance, beginning of year $ 51,472,897 $ 51,340,554 $ 52,230,584
Net income 28,323,338 23,792,979 22,049,207
79,796,235 75,133,533 74,279,791
Less dividends paid:
8 1/8% preferred stock 2,027,390 2,031,250 2,031,250
5% preferred stock 195,090 195,090 195,090
4 3/4% preferred stock 190,000 190,000 190,000
Common stock 21,676,976 21,244,296 20,522,897
24,089,456 23,660,636 22,939,237
Balance, end of year $ 55,706,779 $ 51,472,897 $ 51,340,554
<footnote>
The accompanying notes are an integral part of these financial statements.
Statement of Cash Flows
Year ended December 31,
1998 1997 1996
Operating activities
Net income $ 28,323,338 $ 23,792,979 $ 22,049,207
Adjustments to reconcile net income to cash flows:
Depreciation and amortization 28,323,595 26,510,851 24,314,157
Pension income (2,239,850) (725,198) (1,074,130)
Deferred income taxes, net 3,390,000 2,800,000 3,760,000
Investment tax credit, net (580,000) (590,000) (580,000)
Allowance for equity funds used
during construction (8,938) (150,524) (538,844)
Issuance of common stock for 702,801 660,162 648,535
401 (k) plan
Issuance of common stock units for
director retirement plan 711,000
Other 66,955 129,259 141,882
Cash flows impacted by changes in:
Accounts receivable and accrued
unbilled revenues (584,001) 1,132,283 (1,164,692)
Fuel, materials and supplies (2,489,610) 1,220,673 76,157
Prepaid expenses and deferred 191,956 (1,049,440) (2,077,625)
charges
Accounts payable and accrued 2,233,691 255,402 298,682
liabilities
Customer deposits, interest and 84,941 741,425 (631,954)
taxes accrued
Other liabilities and other 356,750 265,966 (149,401)
deferred credits
Net cash provided by 58,482,628 54,993,838 45,071,974
operating activities
Investing activities
Construction expenditures (51,917,153) (56,673,275) (62,277,486)
Allowance for equity funds used
during construction 8,938 150,524 538,844
Net cash used in (51,908,215) (56,522,751) (61,738,642)
investing activities
Financing activities
Proceeds from issuance of $ 49,672,000 $ - $ 25,000,000
first mortgage bonds
Proceeds from issuance of 5,109,701 5,150,561 20,194,860
common stock
Reacquired preferred stock (267,537)
Dividends (24,089,456) (23,660,636) (22,939,237)
Repayment of first mortgage (23,000,000) (165,000) (187,000)
bonds
Net proceeds (repayments) from
short-term borrowings (13,500,000) 20,500,000 (6,500,000)
Payment of debt issue costs (551,687) 3,134 (472,595)
Net cash (used in)/provided by
financing activities (6,626,979) 1,828,059 15,096,028
Net increase (decrease) in (52,566) 299,146 (1,570,640)
cash and cash equivalents
Cash and cash equivalents, 2,545,282 2,246,136 3,816,776
beginning of year
Cash and cash equivalents, $ 2,492,716 $ 2,545,282 $ 2,246,136
end of year
<footnote>
Cash and cash equivalents include cash on hand and temporary investments
purchased with an initial maturity of three months or less. Interest paid was
$17,439,000, $17,123,000, $14,786,000 for the years ended December 31, 1998,
1997 and 1996, respectively. Income taxes paid were $14,088,000, $10,250,000
and $9,479,000 for the years ended December 31, 1998, 1997 and 1996,
respectively.
The accompanying notes are an integral part of these financial statements.
Notes to Financial Statements
1. Summary of Accounting Policies
The Company is 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 Commision (APSC) and the Federal Energy Regulatory Commission (FERC).
The accounting policies of the Company are in accordance with the rate-making
practices of the regulatory authorities and, as such, conform to generally
accepted accounting principles as applied to regulated public utilities. The
Company's electric revenues in 1998 were derived as follows: residential 42%,
commercial 30%, industrial 17%, wholesale 7% and other 4%. Following is a
description of the Company's significant accounting policies:
Property and plant
The costs of additions to property and 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. 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 as approved by
regulatory authorities. Such provisions approximated 3.2%, 3.1% and 3.2% of
depreciable property for 1998, 1997 and 1996, respectively.
Computations of earnings per share
Basic earnings per share is 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 stock options and their
equivalents. The weighted average number of common shares outstanding used
to compute basic earnings per share for the 1998, 1997 and 1996 periods was
16,932,704, 16,599,269 and 16,015,858, respectively. Dilutive stock options
for the 1998, 1997 and 1996 periods were 7,775, 9,844 and 7,917, 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 (AFUDC) 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 the
Company's 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, the Company utilized
aggregate rates of 5.9% for 1998, 6.4% for 1997 and 7.5% for 1996 (on a
before-tax basis) compounded semiannually.
Notes to Financial Statements
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.
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.
Accrued unbilled revenue
The Company accrues on its books estimated, but unbilled, revenue and also a
liability for the related taxes.
Accumulated provision for uncollectible accounts
The accumulated provision for uncollectible accounts was $276,000 at December
31, 1998 and $279,000 at December 31, 1997.
Franchise taxes
Franchise taxes are collected for and remitted to their respective cities.
Operating revenues include franchise taxes of $4,400,000, $3,900,000 and
$3,800,000 for each of the years ended December 31, 1998, 1997 and 1996,
respectively.
Liability insurance
The Company carries 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 loss experience of the Company.
Use of estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements.
Estimates also affect the reported amounts of revenues and expenses during
the report period. Actual amounts could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current
year presentation. These reclassifications have no effect on previously
reported net income or stockholders' equity.
2. Regulatory Matters
During the three years ending December 31, 1998, the following rate changes
were requested or in effect:
Notes to Financial Statements
Arkansas
On February 19, 1998, the Company filed a request with the Arkansas Public
Service Commission to increase rates in Arkansas by $618,000 annually. An
agreement was reached to stipulate an increase of $359,000 on June 16, and
the Company received an order from the Arkansas Commission on July 21,
approving the stipulated rate increase.
Missouri
On August 30, 1996, the Company filed a request with the Missouri Public
Service Commission for a general annual increase in rates for its Missouri
electric customers of approximately $23,400,000, or 13.8%. A stipulated
agreement was filed by the parties for approximately $13,950,000, and on July
17, 1997, the Missouri Commission issued an order approving an annual
increase in rates in the amount of approximately $10,600,000, or 6.43%
effective July 28, 1997. The amount did not include the Company's investment
in Unit No. 2 at the Company's State Line Plant because the Commission deemed
that Unit No. 2 did not meet all the specified in-service criteria. On July
25, 1997, the Company filed an Application for Rehearing regarding the status
of Unit No. 2, seeking to recover the remaining $3,350,000 of the stipulated
agreement. On September 11, 1997, the Missouri Commission issued an order
approving an additional annual increase in rates in the amount of $3,000,000,
or 1.7% effective September 19, 1997, making the total increase in annual
revenue from this proceeding approximately $13,600,000, or 8.25%.
FERC
In July 1996, the Company filed with the FERC an open access non-
discriminatory transmission tariff (the Company Tariff) in compliance with
FERC Order 888 issued in April 1996. In January 1997, the FERC staff and
intervenors reached a settlement in principal to base rates on traditional
cost of service methodology. After extensive review by the FERC and
discussion with all parties involved, an agreement was reached and approved
by the FERC on August 1, 1997 with rates made effective July 9, 1996. For
customers with service agreements in effect, the Company Tariff will not be
applicable until a rate increase has been filed which may not be made prior
to June 1999.
On December 19, 1997, the Southwest Power Pool (SPP), a power pool with whom
the Company is a member, filed an open access transmission tariff (the
Regional Tariff) on behalf of its members to provide pool-wide, short term
transmission services using pricing which is based on distance. As of
June 1, 1998 the date the FERC declared the Regional Tariff effective, the
SPP began providing short-term firm and non-firm point-to-point transmission
service for periods of less than one year under this tariff. The SPP filed
an amended open access tariff on December 1, 1998 to include long-term firm
point-to-point transmission service. The FERC accepted the amended tariff
making it effective April 1, 1999. The rate charged will be a single system-
wide rate based on the weighted average cost of each SPP member's zone
through which the load passes. The rates for each zone are based on such
member's rates for long-term firm service based on its individual open access
tariff. In addition, if the load originates in a particular member's zone,
then the system-wide rate will be based solely on such member's rate under
its own tariff.
The Regional Tariff as amended will apply to many of the transmission
services for which the Company Tariff was designed. However, the Company
Tariff would still apply instead of the Regional Tariff for (1) all
transmission services for which the load originates within the Company's zone
and does not pass through the zone of any members of the SPP and (2) for all
long-term firm point-to-point transmission services provided by the Company
pursuant to contracts entered into prior to April 1, 1999. The availability
of purchased power in the bulk power market, generation fuel costs and the
requirements of other electric systems are all factors that affect the amount
Notes to Financial Statements
of power purchased and wheeled through the Company's and the SPP's transmission
system each year. As a result the Company cannot predict the effect of these
tariffs on its future operation or financial result due to its inability to
predict these factors.
Effects of Regulation
In accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71), the
Company's financial statements reflect ratemaking policies prescribed by the
regulatory commissions having jurisdiction over the Company (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, the Company has recorded the following 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 the Company's regulators to have been prudently incurred
have been recoverable through rates in the course of normal ratemaking
procedures and the Company believes that the items detailed below will be
afforded similar treatment.
The Company recorded the following regulatory assets and regulatory liability:
December 31,
1998 1997
Regulatory Assets
Income taxes $ 24,666,959 $ 24,781,882
Unamortized loss on reacquired debt 9,352,691 9,912,255
Asbury five year maintenance 1,526,029 2,157,493
Other postretirement benefits 453,460 467,062
Deferred 1993 flood losses - 74,837
Incremental purchased power - 1993 flood - 78,696
Total Regulatory Assets $ 35,999,139 $ 37,472,225
Regulatory Liability
Income taxes $ 16,400,125 $ 17,540,757
The Company continually assesses the recoverability of its 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.
On May 23, 1997, the Missouri Public Service Commission appointed a Retail
Electric Competition Task Force (the Task Force) to prepare reports making
recommendations as to how Missouri should implement retail electric
competition in the event that legislation is enacted that authorizes it. The
task force filed a report May 1, 1998 and the Joint Committee of the State
Legislature conducted hearings during 1998. No final conclusions have been
reached as to the timing or content of the legislative action. There can be
no assurance that legislation deregulating the retail electric industry in
Missouri and/or other states in which the Company operates will not be passed
in the future. In the event such legislation is passed, the Company may
determine that it no longer meets the criteria set forth in SFAS 71 with
respect to some or all of the regulatory assets and liabilities. Any
regulatory changes that would require the Company to discontinue SFAS 71
Notes to Financial Statements
based upon competitive or other events may impact the valuation of the
Company's regulatory assets and certain utility plant investments and require
write-offs which could have a material adverse effect on the Company's
financial condition and results of operations, depending on how the treatment
of regulatory and plant assets and liabilities are considered for recovery
by the regulators.
3. Common Stock
On April 9, 1996, the Company issued and sold 880,000 shares of its common
stock to the public with aggregate proceeds, net of expenses and fees, of
$15,044,000. The proceeds from the offering were used to repay short-term
indebtedness or for expenses incurred in connection with the Company's
construction program.
On August 1, 1998, the Company implemented a new 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 lieu
of cash which was how benefits accumulated under the previous cash retirement
plan for directors. The new Director Retirement Plan also provided directors
the opportunity to convert previously earned cash retirement benefits to
common stock units. 100,000 shares are authorized under this new plan. Each
common stock unit earns dividends in the form of common stock units and can
be redeemed for one share 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 the Company's 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 the Company's stock on the
dividend's record date. During 1998, 34,214 units were granted upon
conversion of previously earned retirement benefits, 1,681 units were granted
for services provided in 1998 and 1,068 units were granted pursuant to the
reinvestment plan described below.
The Company's Dividend Reinvestment and Stock Purchase Plan (the Reinvestment
Plan) allows common and preferred stockholders to reinvest dividends paid by
the Company into newly issued shares of the Company's common stock at 95% of
the market price average. Stockholders may also purchase, for cash and
within specified limits, additional stock at 100% of the market price
average. The Company may elect to make shares purchased in the open market
rather than newly issued shares available for purchase under the Reinvestment
Plan. If the Company so elects, the purchase price to be paid by Reinvestment
Plan participants will be 100% of the cost to the Company of such shares.
Participants in the Reinvestment Plan do not pay commissions or service
charges in connection with purchases under the Reinvestment Plan.
The Company's Employee Stock Purchase Plan, which terminates on May 31, 2000,
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 50,268 shares at $18.34, 58,972 shares at $15.53 and
54,706 shares at $16.31 on December 31, 1998, 1997 and 1996, respectively.
Shares were issued at $15.53 per share in 1998, $15.64 per share in 1997 and
$15.42 per share in 1996.
The Company's 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 January 1998, 1997 and 1996, grants for 1,535, 1,414 and 2,289,
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 service with the
Company 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. For other terminations, the
grant is forfeited. During 1998, 1997 and 1996, 2,641, 3,983 and 3,033
shares, respectively, were issued under the Stock Incentive Plan. No options
Notes to Financial Statements
have been granted under the Stock Incentive Plan. In 1996, the Company adopted
the disclosure-only method under SFAS 123, "Accounting for Stock-Based
Compensation." If the fair value based accounting method under this
statement had been used to account for stock-based compensation costs, the
effect on 1998 and 1997 net income and earnings per share would have been
immaterial.
The Company's Employee 401(k) Retirement Plan (the 401(k) Plan) allows
participating employees to defer up to 15% of their annual compensation up to
a specified limit. The Company matches 50% of each employee's deferrals by
contributing shares of the Company's common stock, such matching
contributions not to exceed 3% of the employee's annual compensation. The
Company contributed 33,274, 36,978 and 36,093 shares of common stock in 1998,
1997 and 1996, 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 source of cash in the Statement of
Cash Flows.
At December 31, 1998, 1,549,552 shares remain available for issuance under
the foregoing plans.
4. Preferred Stock
The Company has 5,000,000 shares of $10.00 par value cumulative preferred
stock authorized. At December 31, 1998 and 1997, these shares were designated
as follows:
Shares
1998 1997
Series without mandatory redemption
provisions 3,300,000 3,300,000
Undesignated 1,700,000 1,700,000
In the event of involuntary liquidation, holders of all outstanding series of
preferred stock will be entitled to be paid the $10.00 par value of their
shares plus accumulated and unpaid dividends before any distribution of
assets to holders of common stock.
The Company also has 2,500,000 shares of preference stock authorized,
including 500,000 shares of Series A Participating Preference Stock, none of
which have been issued.
Preferred stock without mandatory redemption provisions
Preferred stock without mandatory redemption provisions issued and
outstanding at December~31, 1998 and 1997 is as follows:
Shares
1998 1997
5% cumulative (400,000 shares authorized) 381,820 390,180
4 3/4% cumulative (400,000 shares authorized) 400,000 400,000
8 1/8% cumulative (2,500,000 shares authorized) 2,480,998 2,500,000
3,262,818 3,290,180
Notes to Financial Statements
In the event of voluntary liquidation or redemption of the 5%, 4 3/4%, and
8 1/8% series of cumulative preferred stock, holders will be entitled to the
following amounts per share plus accumulated and unpaid dividends: 5%
cumulative - $10.50 (aggregate amount $4,009,110); 4 3/4% cumulative - $10.20
(aggregate amount $4,080,000); and 8 1/8% cumulative - $10 (aggregate amount
$24,809,980). The 8 1/8% series of cumulative preferred stock is not
redeemable, however, until on or after June 2, 1999.
On October 15, 1998 and November 16, 1998, the Company repurchased 19,002
shares of 8 1/8% cumulative preferred stock and 8,360 shares of 5% cumulative
preferred stock at a price of $10.38 and $8.42 per share, respectively.
These shares are carried at cost and are classified as treasury stock.
Preference Stock Purchase Rights
The Company had 8,535,918 and 8,388,327 Preference Stock Purchase Rights
(Rights) outstanding at December 31, 1998 and 1997, respectively. 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. Each share of common stock currently has one-half of one Right.
The Rights (other than those held by an acquiring person or group (Acquiring
Person)), which expire July 25, 2000, will be exercisable only if an Acquiring
Person acquires 10% or more of the Company's common stock or announces an
intention to make a tender offer or exchange offer which would result in the
Acquiring Person owning 10% or more of the common stock. The Rights may be
redeemed by the Company 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 the Company's common stock by an Acquiring Person.
In addition, upon the occurrence of a merger or other business combination,
or an event of the type described in the preceding paragraph, holders of the
Rights, other than an Acquiring Person, will be entitled, upon exercise of a
Right, to receive either common stock of the Company 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 the Company's outstanding common stock, the Board of Directors
may, at its option, exchange part or all of the Rights (other than Rights held
by the Acquiring Person) for common stock of the Company on a one-for-two
basis.
Notes to Financial Statements
5. Long-term Debt
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 property, plant and equipment is subject to the lien of the mortgage. At
December 31 the long-term debt outstanding was as follows:
1998 1997
First mortgage bonds:
5.70% Series due 1998 $ - $ 23,000,000
7 1/2% Series due 2002 37,500,000 37,500,000
7.60% Series due 2005 10,000,000 10,000,000
8 1/8% Series due 2009 (1) 20,000,000 20,000,000
6 1/2 Series due 2010 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 13,726,000 13,726,000
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
246,676,000 219,676,000
Less current maturities - (23,000,000)
Less unamortized net discount (583,095) (291,459)
$ 246,092,905 $ 196,384,541
<footnote>
(1) Holders of this series have the right to require the Company to
repurchase all or any portion of the bonds at a price of 100% of the
principal amount plus accrued interest, if any, on November 1, 2001.
The carrying amount of the Company's long-term debt was $246,676,000 and
$219,676,000 at December 31, 1998 and 1997, respectively, and its fair market
value was estimated to be approximately $252,155,000 and $226,115,000,
respectively. This estimate was based on the quoted market prices for the
same or similar issues or on the current rates offered to the Company 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.
At December 31, 1998, the Company had a $15,000,000 unsecured line of credit.
Borrowings are at the bank's prime commercial rate and are due 370 days from
the date of each loan. In connection with the Company's line of credit,
there is an informal compensating balance arrangement under which the Company
maintains deposits averaging 5% of the line of credit. This arrangement does
not serve to legally restrict the use of the Company's cash. The line of
credit is also utilized to support the Company's issuance of commercial paper
although it is not assigned specifically to such support. There were no
outstanding borrowings under this agreement at December 31, 1998 or 1997.
On April 28, 1998, the Company sold to the public in an underwritten offering
$50 million aggregate principal amount of its First Mortgage Bonds, 6.50%
Series due 2010. The net proceeds from this sale were added to the Company's
general funds and were used to repay $23 million of the Company's First
Mortgage Bonds, 5.70% Series due May 1, 1998 and to repay short-term
indebtedness, including indebtedness incurred in connection with the
Company's construction program.
Notes to Financial Statements
On December 10, 1996, the Company sold to the public in an underwritten offering
$25,000,000 aggregate principal amount of its First Mortgage Bonds, 7.20%
Series due 2016, the proceeds of which were added to the Company's general
funds and used to repay short-term indebtedness or for expenses incurred in
connection with the Company's construction program.
6. Short-term Borrowings
Short-term commercial paper outstanding and notes payable averaged
$11,274,000 and $19,556,000 daily during 1998 and 1997, respectively, with
the highest month-end balances being $28,500,000 and $34,000,000,
respectively. The weighted daily average interest rates during 1998, 1997
and 1996 were 5.9%, 5.9% and 5.6%, respectively. The weighted average interest
rates of borrowings outstanding at December 31, 1998, 1997 and 1996 were
6.2%, 6.1% and 5.8%, respectively.
7. Retirement Benefits
Pensions
The Company's 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.
The following table sets forth the plan's projected benefit obligation, the
fair value of the plan's assets and its funded status:
1998 1997 1996
Benefit obligation at beginning of $ 78,360,097 $ 66,805,630 $ 67,083,122
year
Service cost 2,400,303 2,095,442 1,987,057
Interest cost 5,046,012 4,956,356 4,695,105
Amendments (277,808)
Actuarial (gain)/loss (4,065,095) 9,251,195 (2,494,118)
Benefits paid (4,455,719) (4,470,718) (4,465,536)
Benefit obligation at end of year $ 77,285,598 $ 78,360,097 $ 66,805,630
Fair value of plan assets at
beginning of year $ 82,106,242 $ 70,970,880 $ 69,225,616
Actual return on plan assets 15,503,378 15,606,080 6,210,800
Benefits paid (4,455,719) (4,470,718) (4,465,536)
Fair value of plan assets at
end of year $ 93,153,901 $ 82,106,242 $ 70,970,880
Funded status 15,868,303 3,746,145 4,165,250
Unrecognized net assets at
January 1, 1986 being amortized
over 17 years (1,964,623) (2,455,778) (2,946,933)
Unrecognized prior service cost 3,560,847 3,964,146 4,645,253
Unrecognized net gain (18,028,407) (8,058,243) (9,392,499)
Accrued pension cost $ (563,880) $ (2,803,730) $(3,528,929)
Notes to Financial Statements
Assumptions used in calculating the projected benefit obligation for 1998 and
1997 include the following:
1998 1997 1996
Weighted average discount rate 7.00% 6.75% 7.50%
Rate of increase in compensation levels 5.50% 5.50% 5.50%
Expected long-term rate of return on plan assets 9.00% 9.00% 9.00%
Net pension benefit for 1998, 1997 and 1996 is comprised of the following
components:
1998 1997 1996
Service cost - benefits earned
during the period $ 2,400,303 $ 2,095,442 $ 1,987,057
Interest cost on projected
benefit obligation 5,046,012 4,956,356 4,695,105
Expected return on plan assets (7,173,641) (6,169,097) (6,009,653)
Net amortization and deferral (2,512,524) (1,607,900) (1,746,639)
Net pension benefit $ (2,239,850) $ (725,199) $ (1,074,130)
Other Postretirement Benefits
The Company provides 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, the Company adopted SFAS 106, which requires
recognition of these benefits on an accrual basis during the active service
period of the employees. The Company elected to amortize its transition
obligation (approximately $21.7 million) related to SFAS 106 over a twenty
year period. Prior to adoption of SFAS 106, the Company 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
SFAS 106 costs through rates.
In accordance with the above rate orders, the Company 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. The Company's 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 $6,800,000 at December 31,
1998 and $5,700,000 at December 31, 1997.
Notes to Financial Statements
Postretirement benefits, a portion of which have been capitalized and/or
deferred, for 1998, 1997 and 1996 included the following components:
1998 1997 1996
Service cost on benefits earned
during the year $ 558,983 $ 434,397 $ 472,943
Interest cost on projected
benefit obligation 1,593,181 1,559,110 1,679,461
Return on assets (375,581) (290,079) (142,462)
Amortization of unrecognized
transition obligation 1,084,017 1,084,017 1,084,017
Unrecognized net (gain)/loss (720,744) (1,111,795) (486,691)
Other - (92,890) -
Net periodic postretirement
benefit cost $ 2,139,856 $ 1,582,760 $ 2,607,268
The estimated funded status of the Company's obligations under SFAS 106 at
December 31, 1998, 1997 and 1996 using a weighted average discount rate of
7.0%, 6.75% and 7.5%, respectively, is as follows:
1998 1997 1996
Benefit obligation at beginning
of year $ 23,978,240 $ 20,850,702 $ 23,215,798
Service cost 558,983 434,397 472,943
Interest cost 1,593,181 1,559,110 1,679,461
Actuarial (gain)/loss (353,055) 2,080,611 (3,939,393)
Benefits paid (1,196,552) (946,580) (578,107)
Benefit obligation at end of year $ 24,580,797 $ 23,978,240 $ 20,850,702
Fair value of plan assets at
beginning of year $ 5,691,142 $ 4,829,610 $ 2,963,556
Employer contributions 2,102,087 1,518,033 2,231,009
Actual return on plan assets 206,625 290,079 213,152
Benefits paid (1,196,552) (946,580) (578,107)
Fair value of plan assets at
end of year $ 6,803,302 $ 5,691,142 $ 4,829,610
Funded Status $(17,777,495) $(18,287,098) $(16,021,092)
Unrecognized transition obligation 15,176,225 16,260,242 17,344,259
Unrecognized net gain (1,787,030) (2,323,675) (5,649,391)
Accrued postretirement
benefit cost $ (4,388,300) $ (4,350,531) $ (4,326,224)
The assumed 1999 cost trend rate used to measure the expected cost of
healthcare benefits is 7.5%. The trend rate decreases through 2026 to an
ultimate rate of 6% for 2027 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 $2.2 million to $2.8
million and the accumulated postretirement benefit obligation from $24.6
million to $30.5 million.
Notes to Financial Statements
8. 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:
1998 1997 1996
Computed "expected"
federal provision $ 15,480,000 $ 12,825,000 $ 11,810,000
State taxes, net of federal effect 1,370,000 930,000 1,100,000
Adjustment to taxes resulting from:
Investment tax credit amortization (580,000) (590,000) (580,000)
Other (370,000) (315,000) (630,000)
Actual provision $ 15,900,000 $ 12,850,000 $ 11,700,000
Income tax expense components for the years shown are as follows:
1998 1997 1996
Taxes currently payable
Included in operating
revenue deductions:
Federal $ 12,110,000 $ 9,830,000 $ 7,500,000
State 1,430,000 960,000 1,120,000
Included in "other - net" (450,000) (150,000) (100,000)
13,090,000 10,640,000 8,520,000
Deferred taxes
Depreciation and
amortization differences 3,237,000 3,210,000 3,283,000
Loss on reacquired debt (213,000) (227,000) (249,000)
Postretirement benefits 528,000 159,000 251,000
Other 79,000 (542,000) (344,000)
Asbury five year maintenance (241,000) 200,000 819,000
Deferred investment tax
credits, net (580,000) (590,000) (580,000)
Total income tax expense $ 15,900,000 $ 12,850,000 $ 11,700,000
Notes to Financial Statements
Under SFAS 109, temporary differences gave rise to deferred tax assets and
deferred tax liabilities at year end 1998 and 1997 as follows:
Balances as of December 31,
1998 1997
Deferred Tax Deferred Tax Deferred Tax Deferred Tax
Assets Liabilities Assets Liabilities
Noncurrent
Depreciation and other
property related $ 11,296,127 $ 88,422,060 $ 11,877,844 $ 85,111,843
Unamortized investment
tax credits 5,275,124 - 5,639,749 -
Miscellaneous book/tax
recognition differences 4,471,137 6,380,690 4,557,129 6,307,532
Total deferred taxes $ 21,042,388 $ 94,802,750 $ 22,074,722 $ 91,419,375
9. Iatan Plant
The Company owns a 12% undivided interest in a coal-fired 670 megawatt
generating unit near Weston, Missouri. The Company is entitled to 12% of the
available capacity and is obligated for that percentage of costs which are
included in corresponding operating expense classifications in the Statement
of Income. At December 31, 1998 and 1997, the Company's property, plant and
equipment accounts include the cost of its ownership interest in the unit of
$44,628,000 and $44,489,000, respectively, and accumulated depreciation of
$27,045,000 and $25,418,000, respectively.
10. Commitments and Contingencies
The Company's 1999 construction budget is $64,600,000. The Company's
three-year construction program for 1999 through 2001 is estimated to be
approximately $229,900,000. The Company has announced plans to build a 350
megawatt addition to the State Line Power Plant which, when combined with the
existing State Line Unit No. 2 combustion turbine, will result in a nominal
500 megawatt combined cycle unit. On February 4, 1999, the Company announced
that it entered into a Memorandum of Understanding with another utility and
expects to enter a joint ownership agreement resulting in the Company owning
a 60% undivided interest in the plant. Expenditures relating to the combined
cycle unit totaling approximately $100,000,000 are included in the 1999 through
2001 estimated construction budget. The construction budget does not include
approximately $16,000,000 for nitrogen oxide control equipment expenditures
potentially required as a result of a September 1998 Environmental Protection
Agency ruling.
The Company has entered into long-term agreements to purchase capacity and
energy, to obtain supplies of coal and to provide natural gas transportation.
Under such contracts, the Company incurred purchased power and fuel costs of
approximately $64,000,000, $55,000,000 and $52,000,000 in 1998, 1997 and
1996, respectively. Certain of these contracts provide for minimum and
maximum annual amounts to be purchased and further provide, in part, for cash
settlements to be made when minimum amounts are not purchased. In the event
that no purchases of coal, energy and transportation services are made, an
event considered unlikely by management, minimum annual cash settlements would
approximate $31,000,000 in 1999, $33,000,000 in 2000, $31,000,000 in 2001 and
$27,000,000 in 2002 and reducing to lesser amounts thereafter through 2012.
Notes to Financial Statements
11. Selected Quarterly Information (Unaudited)
A summary of operations for the quarterly periods of 1998 and 1997 is as
follows:
Quarters
First Second Third Fourth
(dollars in thousands except
per share amounts)
1998:
Operating revenues $ 51,388 $ 56,269 $ 77,860 $ 54,341
Operating income 8,060 11,032 19,024 9,256
Net income 3,340 6,211 14,105 4,667
Net income applicable
to common stock 2,736 5,607 13,501 4,068
Basic and diluted earnings
per average share of
common stock $ .16 $ .33 $ .80 $ .24
Quarters
First Second Third Fourth
(dollars in thousands except
per share amounts)
1997:
Operating revenues $ 47,305 $ 45,980 $ 68,636 $ 53,390
Operating income 7,073 6,692 17,375 9,822
Net income 3,125 2,649 12,692 5,327
Net income applicable
to common stock 2,521 2,045 12,088 4,723
Basic and diluted earnings
per average share of
common stock $ .15 $ .12 $ .73 $ .28
<footnote>
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.
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 the Company's proxy statement for
its Annual Meeting of Stockholders to be held April 22, 1999, 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 the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation may be found in the Company's
proxy statement for its Annual Meeting of Stockholders to be held April 22,
1999, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the number of shares of the Company's equity
securities beneficially owned by the directors and certain executive officers
of the Company and by the directors and executive officers as a group may be
found in the Company's proxy statement for its Annual Meeting of Stockholders
to be held April 22, 1999, which is incorporated herein by reference.
To the knowledge of the Company, no person is the beneficial owner of 5% or
more of any class of the Company's voting securities, and there are no
arrangements the operation of which may at a subsequent date result in a
change in control of the Company.
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 the Company's proxy statement for
its Annual Meeting of Stockholders to be held April 22, 1999, which is
incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Index to Financial Statements and Financial Statement Schedule Covered by
Report of Independent Auditors
Balance sheets at December 31, 1998 and 1997............................. 26
Statements of income for each of the three years in the period ended December
31, 1998................................................................ 27
Statements of common stockholders' equity for each of the three years in the
period ended December 31, 1998.......................................... 28
Statements of cash flows for each of the three years in the period ended
December 31, 1998........................................................ 29
Notes to financial statements............................................ 30
Schedule for the years ended December 31, 1998, 1997 and 1996:
Schedule II - Valuation and qualifying accounts......................... 48
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 the Company (Incorporated
by reference to Exhibit 4(a) to Form S-3, File No. 33-54539).
(b) - By-laws of Company as amended January 23, 1992 (Incorporated by
reference to Exhibit 3(f) to Annual Report Form 10-K for year ended
December 31, 1991, File No. 1-3368).
(4) (a) - Indenture of Mortgage and Deed of Trust dated as of September 1,
1944 and First Supplemental Indenture thereto (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) - Eighteenth Supplemental Indenture dated as of July 1, 1992 to
Indenture of Mortgage and Deed of Trust (Incorporated by reference
to Exhibit 4 to Form 10-Q for quarter ended June 30, 1992, File No.
1-3368).
(g) - 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).
(h) - 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).
(i) - 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).
(j) - 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).
(k) - 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).
(l) - 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 Form S-3, File No. 33-56635).
(m) - 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).
(n) - 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).
(o) - 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).
(p) - 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).
(q) - Rights Agreement dated July 26, 1990 (Incorporated by reference to
Exhibit 4(a) to Form 8-K, dated July 26, 1990, File No. 1-3368).
(r) - Amendment to Rights Agreement dated July 26, 1990 between the
Company and Chemical Bank (successor to Manufacturers Hanover Trust
Company), as Rights Agent (Incorporated by reference to Exhibit 4
to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368).
(10)(a) - 1986 Stock Incentive Plan as amended July 23, 1992 (Incorporated by
reference to Exhibit 10 to Form 10-Q for quarter ended June 30,
1992, File No. 1-3368).**
(b) - 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1
to Form S-8, File No. 33-64639).**
(c) - Management Incentive Plan (A description of this Plan is
incorporated by reference to page 5 of the Company's Proxy
Statement for its Annual Meeting of Stockholders held April 27,
1989). **
(d) - 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). **
(e) - 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). **
(f) - 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). **
(g) - The Empire District Electric Company Supplemental Executive
Retirement Plan. (Incorporated by reference to Exhibit 10(e) to
Annual Report on Form 10-K for year ended December 31, 1994, File
No. 1-3368). **
(h) - Retirement Plan for Directors as amended August 1, 1998
(Incorporated by reference to Exhibit 10(a) to Form Q for quarter
ended September 30, 1998, File No. 1-3368). **
(i) - 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). **
(12) - Computation of Ratios of Earnings to Fixed Charges and Earnings to
Combined Fixed Charges and Preferred Stock Dividend Requirements.*
(23) - Consent of Price Waterhouse.*
(24) - Powers of Attorney.*
(27) - Financial Data Schedule for December 31, 1998.
** This exhibit is a compensatory plan or arrangement as contemplated by Item
14(a)(3) of Form 10-K.
* Filed herewith
Reports on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of 1998.
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 1998, 1997 and 1996
Balance Additions Deductions from reserve Balance
At Charged to Other Accounts at
Beginning Charged Description Amount Description Amount close of
of period to income period
Year ended December 31, 1998:
Reserve deducted from assets: Recovery of
Accumulated provision for amounts previously Accounts
Uncollectible accounts $ 278,741 $ 586,000 written off $ 448,718 written off $ 1,037,583 $ 275,876
Reserve not shown separately Property, plant &
in balance sheet: equipment and
Injuries and damages clearing accounts Claims and
Reserve (Note A) $1,311,995 $ 580,832 $ 530,011 expenses $ 1,108,377 $ 1,314,461
Year ended December 31, 1997:
Reserve deducted from assets: Recovery of
Accumulated provision for amounts previously Accounts
Uncollectible accounts $ 265,390 $ 486,000 written off $ 332,632 written off $ 805,281 $ 278,741
Reserve not shown separately
in balance sheet: Property, plant &
Injuries and damages equipment and Claims and
reserve (Note A) $1,300,917 $ 484,541 clearing accounts $ 472,107 expenses $ 945,570 $ 1,311,995
Year ended December 31, 1996:
Reserve deducted from assets: Recovery of
Accumulated provision for amounts previously Accounts
Uncollectible accounts $ 257,861 $ 558,458 written off $ 459,159 written off $ 1,010,088 $ 265,390
Reserve not shown separately
in balance sheet: Property, plant &
Injuries and damages equipment and Claims and
Reserve (Note A) $1,263,050 $ 508,280 clearing accounts $ 446,212 expenses $ 916,625 $ 1,300,917
<footnote>
NOTE A: This reserve is provided for workers' compensation, certain
postemployment benefits and public liability damages. The Company at December
31, 1998 carried insurance for workers' compensation claims in excess of
$250,000 and for public liability claims in excess of $300,000. The injuries
and damages reserve is included on the Balance Sheet in the section
"Noncurrent liabilities and deferred credits" in the category "Other".
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
THE EMPIRE DISTRICT ELECTRIC COMPANY
By M. W. MCKINNEY
----------------------------
Date: March 9, 1999 M. W. McKinney, President
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.
Date
M. W. MCKINNEY
----------------------------------------------
M. W. McKinney, President and Director
(Principal Executive Officer)
R. B. FANCHER
----------------------------------------------
R. B. Fancher, Vice President-Finance
(Principal Financial Officer)
G. A. KNAPP
----------------------------------------------
G. A. Knapp, Controller and Assistant Treasurer
(Principal Accounting Officer)
V. E. BRILL*
-----------------------------------------------
V. E. Brill, Vice President-Energy Supply and Director
M. F. CHUBB, JR.*
----------------------------------------------
M. F. Chubb, Jr., Director
R. D. HAMMONS*
----------------------------------------------
R. D. Hammons, Director
March 9, 1999
R. C. HARTLEY*
----------------------------------------------
R. C. Hartley, Director
J. R. HERSCHEND*
----------------------------------------------
J. R. Herschend, Director
F. E. JEFFRIES*
---------------------------------------------
F. E. Jeffries, Director
R. E. MAYES*
---------------------------------------------
R. E. Mayes, Director
R. L. LAMB*
---------------------------------------------
R. L. Lamb, Director
M. M. POSNER*
---------------------------------------------
M. M. Posner, Director
R. B. FANCHER
*By------------------------------------------
(R. B. Fancher, As attorney in fact for
each of the persons indicated)