UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1999 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
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 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. [
As of March 1, 2000, 17,336,923 shares of common stock were outstanding.
Based upon the closing price on the New York Stock Exchange on March 1,
2000, the aggregate market value of the common stock of the Company held
by nonaffiliates was approximately $353,239,806.
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 1999 Part of Item 12 of Part
Annual Meeting of III
Stockholders to be held on All of Item 13 of Part
April 27, 2000. III
TABLE OF CONTENTS
Page
Forward Looking Statements 3
PART I
ITEM 1. BUSINESS 3
General 3
Electric Generating Facilities and Capacity 4
Construction Program 5
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 2. PROPERTIES 10
Electric Facilities 10
Water Facilities 12
ITEM 3. LEGAL PROCEEDINGS 12
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 12
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED 12
STOCKHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL DATA 14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS 15
Merger With UtiliCorp 15
Results of Operations 16
Liquidity and Capital Resources 20
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 23
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE 43
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 43
ITEM 11.EXECUTIVE COMPENSATION 43
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 43
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 43
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 44
SIGNATURES 47
FORWARD LOOKING STATEMENTS
Certain matters discussed in this annual report are "forward-
looking statements" intended to qualify for the safe harbors 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 construction of the State Line Combined Cycle Unit),
earnings, competition, litigation, rate and other regulatory
matters, liquidity and capital resources, 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; a
significant delay in the expected completion of, and unexpected
consequences resulting from the merger with UtiliCorp; delays in or
increased costs of construction; 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.
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 1999, 99.5% of the Company's gross operating revenues
were provided from the sale of electricity and 0.5% from the sale
of water.
The Company and UtiliCorp United, Inc. entered into an
Agreement and Plan of Merger, dated as of May 10, 1999, which
provides for a merger of the Company with and into UtiliCorp, with
UtiliCorp being the surviving corporation. At a special meeting of
stockholders held on September 3, 1999, the merger was approved by
the Company's stockholders. The merger is conditioned, among other
things, upon approvals of various federal and state regulatory
agencies. See Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" for further
information.
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 1999 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 121
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 24% of the Company's electric operating revenues in
1999 were derived from incorporated communities with franchises
having at least ten years remaining and approximately 36% 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 1999 were derived
as follows: residential 41%, commercial 31%, industrial 17%,
wholesale 7% and other 4%. The Company's largest single on-system
wholesale customer is the city of Monett, Missouri, which in 1999
accounted for approximately 3% of electric revenues. No single
retail customer accounted for more than 1% of electric revenues in
1999.
The Company made an investment of approximately $0.5 million
in 1999 and $3.5 million in 1998 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, generators, surge suppressors,
decorative lighting and other energy services.
Electric Generating Facilities and Capacity
At December 31, 1999, 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.
The Company is currently constructing a 350 megawatt expansion at
the State Line Power Plant which will result in a 500 megawatt
combined-cycle unit (the "State Line Combined Cycle Unit") with
commercial operation scheduled for June 2001. This is a joint
effort with Westar Generating, Inc. ("WGI"), a subsidiary of
Western Resources, Inc., from which the Company will be entitled to
approximately 150 megawatts of additional generating capacity. See
Item 2, "Properties - Electric Facilities" for further information
about these plants.
The Company is a member of the Southwest Power Pool ("SPP"), a
regional division of the North American Electric Reliability
Council ("NERC"). The SPP currently requires its members to
maintain a 12% capacity reserve margin and provides for contingency
reserve sharing, regional near real-time security assessment 24
hours per day and many other functions. The Company is
participating with other utility members in the restructuring of
SPP to make it a regional transmission organization ("RTO"). See
Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Competition." 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 other 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") for periods
through the contract year 1999 which ends May 31, 2000, and with
Western Resources ("WR") 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 WR 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 all of the
contracts described above, except the WR contract, and the
installation of additional generation that is expected to be
available upon completion of construction of the State Line Project
in the summer of 2001. The Company currently expects to purchase
additional capacity to meet reserve margins in 2003 and 2004 of 30
to 60 megawatts based on current forecast of load.
Purchased Anticipated
Contract Power Owned
Year Commitment Capacity Total
1999 255 878 1133
2000 287 878 1165
2001 162 1026 1188
2002 162 1026 1188
2003 162 1026 1188
2004 162 1026 1188
The charges for capacity purchases under the contracts referred to
above during calendar year 1999 amounted to approximately $15.9
million. Minimum charges for capacity purchases under such
contracts total approximately $107.8 million for the period June 1,
2000, through May 31, 2005.
The maximum hourly demand on the Company's system reached a
new record high of 979 megawatts on August 12, 1999. The Company's
previous record peak of 916 megawatts was established in August
1998. The Company's maximum hourly winter demand of 841 megawatts,
was set on January 13, 1997.
Construction Program
Total gross property additions (including construction work in
progress) for the three years ended December 31, 1999, amounted to
$176.1 million, and retirements during the same period amounted to
$13.4 million.
The Company's total construction-related expenditures,
including allowance for funds used during construction ("AFUDC"),
were $70.1 million in 1999 and for the next three years are
estimated for planning purposes to be as follows:
Estimated Construction Expenditures
(amounts in millions)
2000 2001 2002 Total
New generating facilities 57.8 17.8 3.5 79.1
Additions to existing 8.9 11.2 16.5 36.6
generating facilities
Transmission facilities 15.2 7.2 4.4 26.8
Distribution system 21.4 23.1 24.5 69.0
additions
General and other additions 2.4 1.8 2.0 6.2
Total $ 105.7 $ 61.1 $ 50.9 $ 217.7
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. 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.
Estimated construction expenditures are reviewed and adjusted
for, among other things, revised estimates of future capacity
needs, the cost of funds necessary for construction and the
availability and cost of alternative power. Actual construction
expenditures may vary significantly from the estimates due to a
number of factors including changes in equipment delivery
schedules, changes in customer requirements, construction delays,
ability to raise capital, environmental matters, the extent to
which 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 81.8% of the Company's total fuel
requirements in 1999 based on kilowatt-hours generated. The
remainder was supplied by natural gas (18.0%) with oil generation
being insignificant.
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 (Powder
River Basin) and 10% blend coal on a tonnage basis. The Company
has increased its target coal inventory at Asbury from
approximately 45 days to 60 days. As of December 31, 1999, the
Company had sufficient coal on hand to supply anticipated
requirements at Asbury for 71 days.
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% blend coal on a tonnage
basis. The Company has increased its target coal inventory at
Riverton from 45 days to approximately 60 days. As of December 31,
1999, the Company had coal supplies on hand to meet anticipated
requirements at the Riverton Plant for 74 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 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 is currently leasing one 125-car aluminum
unit train, which delivers Peabody coal to the Asbury Plant. The
Peabody coal is transported from Asbury to Riverton via truck.
Anticipated requirements for blend coal are currently being
supplied under spot purchases following the expiration of a coal
supply agreement with the Mackie-Clemens Fuel Company on December
31, 1999.
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 for Energy Center Units 1 and 2 and State
Line Unit No. 1. 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:
1999 1998 1997
Coal - Iatan $0.806 $0.857 $0.871
Coal - Asbury 1.074 1.100 1.088
Coal - Riverton 1.222 1.214 1.235
Natural Gas 2.549 2.495 2.665
Oil 3.869 4.386 4.137
The Company's weighted cost of fuel burned per kilowatt-hour
generated was 1.561 cents in 1999, 1.570 cents in 1998 and 1.397
cents in 1997.
Employees
At December 31, 1999, the Company had 615 full-time employees,
of whom 333 were members of Local 1474 of The International
Brotherhood of Electrical Workers ("IBEW"). On January 17, 2000,
the Company and the IBEW entered into a new three-year labor
agreement effective November 1, 1999. The agreement provides,
among other things, for a 3.25% increase in wages effective October
25, 1999, with additional minimum increases of 2% effective
November 6, 2000 for the second year and effective October 22, 2001
for the third year.
ELECTRIC OPERATING STATISTICS (1)
1999 1998 1997 1996 1995
Electric Operating Revenues (000s):
Residential $ 98,787 $100,567 $ 88,636 $ 86,014 $ 81,331
Commercial 73,773 71,810 64,940 61,811 58,430
Industrial 41,030 39,805 37,192 35,213 32,637
Public authorities 5,847 5,559 4,995 4,180 3,745
Wholesale on-system 10,682 10,928 9,730 9,482 8,360
Miscellaneous 3,856 4,006 3,341 3,639 3,345
Total system 233,975 232,675 208,834 200,339 187,848
Wholesale off-system 7,090 6,126 5,473 4,595 4,000
Total electric operating $241,065 $238,801 $214,307 $204,934 $191,848
revenues
Electricity generated and
purchased (000s of Kwh):
Steam 2,378,130 2,228,103 2,372,914 2,231,062 2,374,021
Hydro 86,349 70,631 77,578 62,860 71,302
Combustion turbine 520,340 439,517 211,872 162,679 170,479
Total generated 2,984,819 2,738,251 2,662,364 2,456,601 2,615,802
Purchased 1,686,782 1,970,348 1,839,833 1,968,898 1,540,816
Total generated and 4,671,601 4,708,599 4,502,197 4,425,499 4,156,618
purchased
Interchange (net) (138) (1,894) 1,018 (1,087) (5,851)
Total system input 4,671,463 4,706,705 4,503,215 4,424,412 4,150,767
Maximum hourly system demand 979,000 916,000 876,000 842,000 815,000
(Kw)
Owned capacity (end of period) 878,000 878,000 878,000 724,000 737,000
(Kw)
Annual load factor (%) 52.16 55.72 55.38 56.85 55.15
Electric sales (000s of Kwh):
Residential 1,509,176 1,548,630 1,429,787 1,440,512 1,350,340
Commercial 1,260,597 1,246,323 1,171,848 1,154,879 1,086,894
Industrial 988,114 960,783 943,287 923,730 859,017
Public authorities 99,739 98,675 101,122 95,652 90,543
Wholesale on-system 297,614 299,256 273,035 262,330 243,869
Total system 4,155,240 4,153,667 3,919,079 3,877,103 3,630,663
Wholesale off-system 198,234 235,391 253,060 219,814 213,590
Total electric sales 4,353,474 4,389,058 4,172,139 4,096,917 3,844,253
Company use (000s of Kwh) 8,583 8,940 9,688 9,584 9,559
Lost and unaccounted for (000s 309,406 308,707 321,388 317,911 296,955
of Kwh)
Total system input 4,671,463 4,706,705 4,503,215 4,424,412 4,150,767
Customers (average number of
monthly bills rendered):
Residential 121,523 119,265 117,271 115,116 112,605
Commercia 22,206 21,774 21,323 20,758 20,098
Industrial 350 354 346 346 339
Public authorities 1,759 1,739 1,720 1,696 1,637
Wholesale on-system 7 7 7 7 7
Total system 145,845 143,139 140,667 137,923 134,686
Wholesale off-system 6 6 7 9 6
Total 145,851 143,145 140,674 137,932 134,692
Average annual sales per 12,419 12,985 12,192 12,514 11,992
residential customer (Kwh)
Average annual revenue per $ 812.91 $ 843.22 $ 755.82 $ 747.19 $ 722.27
residential customer
Average residential revenue per 6.55> 6.49> 6.20> 5.97> 6.02>
Kwh
Average commercial revenue per 5.85> 5.76> 5.54> 5.35> 5.38>
Kwh
Average industrial revenue per 4.15> 4.14> 3.94> 3.81> 3.80>
Kwh
(1) See Item 6 - Selected Financial 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, 1999, 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 12/31/99 Positions with the Company Company since since
M.W.McKinney 55 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 58 Vice President - Energy Supply 1962 1975
(1995), Vice President - Finance
(1983), Director (1989)
R.B. Fancher 59 Vice President - Finance (1995), Vic 1972 1984
President - Corporate Services (1984)
C.A. Stark 55 Vice President - General Services 1980 1995
(1995), Director of Corporate
Planning (1988)
W.L. Gipson 42 Vice President - Commercial 1981 1997
Operations (1997), General Manager
(1997), Director of Commercial
Operations (1995), Economic
Development Manager (1987)
D.W. Gibson 53 Director of Financial Services and 1979 1991
Assistant Secretary (1991)
G.A. Knapp 48 Controller and Assistant Treasurer 1978 1983
(1983)
J.S. Watson 47 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 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, 1999, 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 1999, 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 1999.
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.
The 1990 Amendments require affected plants to meet certain
emission standards, including maximum emission levels for sulfur
dioxide ("SO2") and nitrogen oxide ("NOx"). When a plant becomes
an affected unit for a particular emission, it locks in the then
current emission standards. The Asbury Plant became an affected
unit under the 1990 Amendments for both SO2 and NOx on January 1,
1995. The Riverton Plant became an affected unit for NOx in
November 1996 and for SO2 on January 1, 2000. The Iatan Plant
became 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 1999, the Asbury Plant used approximately 51% 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). The Company anticipates (based on current
operations) that the Asbury Plant will use slightly more allowances
than the number available to it on an annual basis with the deficit
coming from the Company's inventoried bank of allowances. The
Company currently has 36,000 banked allowances.
With respect to the Riverton Plant, the Company is presently
burning a combination of Western coals that will allow the plant to
use approximately the amount of allowances that it receives
annually from the EPA. If the plant requires more allowances than
it has received, the Company will transfer allowances from the
Asbury Plant to the Riverton Plant. The Iatan Unit is expected to
be deficient in allowances by a margin of approximately 20% based
on current operating conditions. Any needed allowances will be
supplied by the respective owners from present inventories or by
open-market purchases.
NOx Emissions. The EPA revised its regulations to require
cyclone units (such as the Asbury Plant) to meet more stringent NOx
requirements by 2000. The Company installed NOx control
modifications in 1999 that have reduced NOx emissions at the Asbury
Plant. The Asbury Plant is in compliance with current NOx
requirements The Iatan Plant and the Riverton Plant are each in
compliance with the NOx limits applicable to them under the 1990
Amendments as currently operated.
In September 1998, the EPA issued its final regulation for a
State Implementation Plan ("SIP") call for NOx requiring the
District of Columbia and 22 Midwestern and Eastern states to reduce
NOx emissions up to 85% below the levels established by the 1990
Amendments. The State of Missouri was included in the final
regulation but Kansas, Arkansas and Oklahoma were not. 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 May 1, 2003. The Company is proceeding with
the development of compliance plans, including preliminary
engineering and cost determination. In 1999, the Company joined
litigation in the Washington D.C. Circuit Court against the EPA NOx
SIP call. One suit has been filed by the Midwest Ozone Group and
another by an alliance of western Missouri utilities. Oral
arguments were heard on November 9, 1999 and a ruling is expected
during the first quarter of 2000. The NOx SIP call requirement
that the Missouri Department of Natural Resources develop its own
SIP by September 1999 was stayed by the Washington D.C. Circuit
Court until a decision on the NOx SIP call litigation is issued.
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 $17 million. The
installation of this equipment would begin in 2002 and its cost is
not included in the Company's current construction budget. If the
litigation is successful, the Company may still need to install
additional NOx control equipment, but the Company cannot estimate
the cost or timing thereof.
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 has
been drafted and is expected to be issued by mid-2000. The
Riverton Plant's National Pollution Discharge Elimination System
("NPDES") Permit expires in September 2000. The Company will apply
for a renewal in March 2000 and does not expect any changes in the
parameters regarding the permit. The State Line Plant is currently
in the process of applying for a new NPDES Permit pertaining to the
expansion of the plant. This permit is needed by July 2001.
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 has
been issued permits for Asbury, State Line and the Energy Center
Power Plants. The Riverton Plant has not been issued an operating
permit at this time. The Company expects this permit will be
issued during 2000.
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, 1999,
the Company could have issued under the Mortgage approximately
$141.8 million principal amount of additional bonds (at an assumed
interest rate of 7.50%). 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, 1999, the Company had retired bonds and
net property additions which would enable the issuance of at least
$148.0 million principal amount of bonds.
Under the Restated Articles, (a) 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)
so long as any preferred stock is outstanding, the amount of
unsecured indebtedness outstanding may not exceed 20% of the sum of
the outstanding secured indebtedness plus the capital and surplus
of the Company. The Company redeemed all of its outstanding
preferred stock on August 2, 1999 and, accordingly, the Articles do
not restrict the amount of unsecured indebtedness that the Company
may have outstanding.
ITEM 2. PROPERTIES
Electric Facilities
At December 31, 1999, 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 1999 accounted for approximately 44% of the energy
generated by the Company and 28% 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.
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
last 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 10 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, presently 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. On July 26, 1999, the
Company and Westar Generating, Inc. ("WGI"), a subsidiary of
Western Resources, Inc., entered into agreements for the
construction, ownership and operation of a 500-megawatt combined-
cycle unit at the State Line Power Plant (the "State Line Combined
Cycle Unit"). This State Line Combined Cycle Unit will consist of
an additional combustion turbine, two heat recovery steam
generators and a steam turbine and auxiliary equipment with an
already existing combustion turbine. Work has begun and the State
Line Combined Cycle Unit is projected to be operational by June
2001. The Company will own an undivided 60% interest in the State
Line Combined Cycle Unit with WGI owning the remainder. The
Company is entitled to 60% of the capacity of the State Line
Combined Cycle Unit. The Company will contribute its existing 152-
megawatt State Line Unit No. 2 combustion turbine to the State Line
Combined Cycle Unit, and as a result, upon commercial operation,
the State Line Combined Cycle Unit will provide the Company with
approximately 150 megawatts of additional capacity. The total cost
of this construction expansion project is estimated to be $185
million. The Company's share of this amount, after the transfer to
WGI of an undivided 40% joint ownership interest in the existing
State Line Unit No. 2 and certain other property at book value as
described below, is expected to be approximately $100 million. See
Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital
Resources."
The Company's hydroelectric generating plant, located on the
White River at Ozark Beach, Missouri, has a generating capacity of
16 megawatts, subject to availability of water. The Company has a
long-term license from FERC to operate this plant which forms Lake
Taneycomo in Southwestern Missouri.
At December 31, 1999, 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 6,204
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. The Company will own a similar interest
in 60% of the land used for the State Line Combined Cycle Unit.
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 79
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, 2000, there were 8,384 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
1999 and 1998 were as follows:
Price of Common Stock Dividends Paid
1999 1998 Per Share
High Low High Low 1999 1998
First Quarter $ 25.625 $ 22.000 $ 22.500 $ 18.375 $ 0.32 $ 0.32
Second Quarter 26.313 20.688 22.500 20.000 0.32 0.32
Third Quarter 26.750 25.375 23.375 19.313 0.32 0.32
Fourth Quarter 25.688 21.688 26.125 20.875 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 any outstanding cumulative preferred
stock and preference stock.
The Mortgage and the Restated Articles contain certain
dividend restrictions. The most restrictive of these is contained
in the Mortgage, which provides that 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. The Company, with the requisite consents of the
holders of bonds issued under the Mortgage, has entered into a
supplemental indenture which amends this dividend restriction so
that a successor corporation would only need to look to earned
surplus accumulated subsequent to August 31, 1944 instead of the
date of succession. This supplemental indenture will not be
effective, however, until the merger with UtiliCorp is completed.
As of December 31, 1999, 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.
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. This provision was amended on May 10, 1999 to exclude
the pending merger with UtiliCorp. See Note 5 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 4 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)
1999 1998 1997 1996 1995
Operating revenues $ 242,162 $ 239,858 $ 215,311 $ 205,984 $ 192,838
Operating income $ 42,576 $ 47,372 $ 40,962 $ 36,652 $ 33,151
Total allowance for funds
used during construction $ 1,193 $ 409 $ 1,226 $ 1,420 $ 2,239
Net income $ 22,170 $ 28,323 $ 23,793 $ 22,049 $ 19,798
(2) (1)
Earnings applicable to $ 19,463 $ 25,912 $ 21,377 $ 19,633 $ 17,381
common stock (2) (1)
Weighted average number of
common
shares outstanding 17,237,805 16,932,704 16,599,269 16,015,858 14,730,902
Basic and diluted earnings $ 1.13 $ 1.53 $ 1.29 $ 1.23 $ 1.18
per weighted (2) (1)
average shares outstanding
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 107.3% 83.7% 99.4% 104.5% 108.9%
Allowance for funds used
during construction as
a percentage of earnings
applicable to common
stock 6.1% 1.6% 5.7% 7.2% 12.9%
Book value per common share
outstanding
at end of year $ 13.44 $ 13.40 $ 13.03 $ 12.93 $ 12.67
Capitalization:
Common equity $234,188 $229,791 $219,034 $213,091 $193,137
Preferred stock without
mandatory
redemption provisions $ 0 $ 32,634 $ 32,902 $ 32,902 $ 32,902
First mortgage bonds $345,850 $246,093 $196,385 $219,533 $194,705
Ratio of earnings to fixed
charges 2.70 3.32 3.01 3.11 2.90
Ratio of earnings to
combined fixed charges
and preferred stock
dividend requirements 2.40 2.78 2.50 2.53 2.36
Total assets $731,220 $653,294 $626,465 $596,980 $557,368
Utility plant in service at
original cost $870,329 $831,496 $797,839 $717,890 $682,609
Utility plant expenditures
during the year $ 69,642 $ 47,366 $ 53,280 $ 59,373 $ 49,217
(1) Reflects a pre-tax charge of $4,583,000 for certain one-time
costs associated with the Company's voluntary early retirement
program.
(2) Reflects $5,772,292 of non-tax-deductible merger costs
associated with the Company's proposed merger with UtiliCorp.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
MERGER WITH UTILICORP
The Company and UtiliCorp United Inc., a Delaware corporation
("UtiliCorp"), have entered into an Agreement and Plan of Merger,
dated as of May 10, 1999 (the "Merger Agreement"), which provides
for a merger of the Company with and into UtiliCorp, with
UtiliCorp being the surviving corporation (the "Merger"). Under
the terms of the Merger Agreement, UtiliCorp will pay $29.50 for
each share of common stock of the Company, payable in UtiliCorp
common stock or cash. The Merger Agreement contains a collar
provision under which the value of the merger consideration per
share will decrease if UtiliCorp's common stock is below $22 per
share preceding the closing and will increase if UtiliCorp's
common stock is above $26 per share preceding the closing. The
average trading price of UtiliCorp's common stock price will be
used to determine the merger consideration and will be calculated
based on the closing prices on the NYSE during the 20 trading days
ending on the third trading day prior to the closing date of the
Merger. If the average trading price is below $22, UtiliCorp will
pay 1.342 times the average trading price for each share of
Company common stock and if the average trading price is above
$26, UtiliCorp will pay 1.135 times the average trading price for
each share of Company common stock. For example, if the Merger
had closed on March 6, 2000, the average trading price for
UtiliCorp's common stock would have been $17.5656 per share,
resulting in the payment of $23.5513 for each share of the
Company's common stock. Stockholders of the Company may elect to
take cash or stock, but total cash paid to stockholders will be
limited to no more than 50% of the total Merger consideration, and
the number of shares of UtiliCorp common stock that may be issued
in the Merger is limited to 19.9% of the number of then
outstanding shares of common stock of UtiliCorp. UtiliCorp also
will become liable for all of the Company's existing debt,
including its first mortgage bonds. See Note 2 of "Notes to
Financial Statements" under Item 8 for further information.
The Merger, which was unanimously approved by the Boards of
Directors of the constituent companies, is expected to close after
all of the conditions to the consummation of the Merger are met or
waived. The Merger is conditioned, among other things, upon
approvals of federal regulatory agencies and approvals of state
regulatory authorities in states where the combined company will
operate. At a special meeting of stockholders held on September
3, 1999, the Merger was approved with 76.3% of the Company's
outstanding shares voting in favor of the proposal. UtiliCorp is
not required to obtain its stockholders' approval of the Merger.
The Company and UtiliCorp filed joint applications with the
FERC on November 23, 1999 and the Missouri Commission on December
14, 1999 requesting approval of the merger. Applications to merge
were filed with the Arkansas Public Service Commission on January
28, 2000 and with the Kansas Corporation Commission and Oklahoma
Corporation Commission on January 31, 2000. The applications set
forth a proposed Regulatory Plan (the "Plan") which would result
in a five-year rate moratorium following the conclusion of a rate
case the Company plans to file in the second half of 2000. This
rate case is designed to recover the costs associated with the
Company's State Line Project anticipated to be operational by June
2001. The Plan also calls for UtiliCorp to keep any savings
generated by the Merger to offset the acquisition premium.
UtiliCorp may file a rate case at the end of the five-year rate
moratorium allowing UtiliCorp to include one half of any
unamortized acquisition premium in the rate base, thus allowing it
to be recovered in rates. The Missouri Commission has scheduled
hearing dates for the Merger proposal for September 11-15, 2000 in
Jefferson City, Missouri, which means a ruling could be issued by
that Commission before the end of this year.
UtiliCorp is a multinational energy and energy services
company headquartered in Kansas City, Missouri. It has regulated
utility operations in eight states and energy operations in New
Zealand, Australia, the United Kingdom and Canada. It also owns
non-utility subsidiaries involved in energy trading; natural gas
gathering, processing and transportation; energy efficiency
services and various other energy-related businesses. For more
information on the Merger, see the Company's proxy statement for
its special meeting of stockholders held on September 3, 1999,
which is dated August 2, 1999.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
results of operations for the year ended December 31, 1999,
compared to the year ended December 31, 1998, and for the year
ended December 31, 1998, compared to the year ended December 31,
1997.
Operating Revenues and Kilowatt-Hour Sales
Of the Company's total electric operating revenues during
1999, approximately 41% were from residential customers, 31% from
commercial customers, 17% from industrial customers, 4% 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
1999 1998 1999 1998
Residential (2.6)% 8.3% (1.8)% 13.5%
Commercial 1.2 6.4 2.7 10.6
Industrial 2.8 1.9 3.1 7.0
Wholesale On- (0.6) 9.6 (2.3) 12.3
System
Total On-System 0.1 6.0 0.6 11.3
Kwh sales for the Company's on-system customers increased
slightly during 1999 while revenues increased slightly more than
the corresponding increase in Kwh sales. Customer growth
increased slightly in 1999 over the 1.8% growth rate in 1998.
Despite above-average temperatures in July and August, residential
Kwh sales decreased 2.6% with revenues decreasing 1.8% as compared
to 1998. This decrease was primarily due to unusually mild
temperatures during the second quarter of 1999, as well as in
September, November and December, and the unusually warm second
and third quarters of 1998. Commercial and industrial classes
showed an increase in Kwh sales and revenues due to continued
increases in business activity throughout the Company's service
territory.
On-system wholesale Kwh sales were down slightly in 1999,
reflecting the mild temperatures discussed above. Revenues
associated with these sales decreased 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 the pass through to customers of changes in fuel and
purchased power costs.
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 than
the annual Kwhs. Revenues and Kwh sales were also positively
impacted by $1.7 million (0.1%),and 32 million Kwhs (0.8%)
respectively, as a result of a change in the estimation of
periodic loss factors used to calculate unbilled revenues.
Customer growth increased slightly to 1.8% in 1998 as compared to
1.7% in 1997. Residential and commercial Kwh sales increased as
compared to 1997, primarily due to the above-average temperatures
discussed above. 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.
On-system wholesale Kwh sales were up significantly in 1998,
reflecting the warm summer temperatures and continued increases in
business activity discussed above. Revenues associated with these
sales increased more than the corresponding Kwh sales as a result
of 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% *
* An increase of $10,589,364 was granted effective 07-28-97.
An additional $3,000,000 increase became effective 09-19-97.
In addition to sales to its own customers, the Company sells
power to other utilities as available and provides transmission
service through its system for transactions between other energy
suppliers. During 1999 revenues from such off-system transactions
were approximately $9.6 million as compared to approximately $8.3
million in 1998 and approximately $7.6 million during 1997. The
increase in revenues during 1999 was primarily the result of an
increase in firm capacity charges as well as an increase in sales
resulting from the ability to sell power at market-based rates.
Pursuant to orders issued by the FERC and subsequent tariffs filed
by the Company and SPP, these off-system sales have been opened up
to competition. See "- Competition" below for more information.
The Company's future revenues from the sale of electricity
will continue to be affected by economic conditions, business
activities, competition, weather, regulation, the utilities'
change from a regulated to a competitive environment, 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.
Operating Revenue Deductions
During 1999, total operating expenses increased approximately
$6.1 million (5.1%) compared to the prior year. Merger related
expenses, which are not tax deductible, contributed $5.8 million
to this increase. A significant portion of these expenses include
payments to the Company's financial advisors for the first and
second portions of the agreed upon transaction fee for their
financial services in connection with the merger. This agreement
calls for payment of 25% of the transaction fee upon execution of
the merger agreement, 25% upon stockholder approval of the merger
and the remaining 50% upon the consummation of the merger, payable
upon closing. Including the final payment to be made under this
agreement, remaining merger costs are expected to total
approximately $11 million.
Total purchased power costs decreased by approximately $2.9
million (6.0%) during 1999, primarily due to increased
availability of the Company's generating units. The Asbury Plant
set a new continuous run record of 190 days in 1999.
Total fuel costs were up approximately $3.4 million (8.1%)
during 1999 as compared to the same period in 1998 primarily
reflecting the increased generation from the higher-cost gas
turbines at the State Line Power Plant. The hot temperatures in
July and August resulted in a significant increase in the price of
purchased power, making it more economical for the Company to run
its gas turbines during those months. In addition, natural gas
prices were higher by 1.5% during 1999 as compared to 1998,
contributing to the increase.
Other operating expenses decreased slightly by approximately
$0.1 million (0.4%) during 1999, compared to 1998. Maintenance
and repairs expense decreased approximately $1.2 million (6.7%)
during 1999 primarily due to decreased maintenance costs at Asbury
and Riverton. The Riverton Plant had a five-year scheduled
maintenance outage in 1998. These decreases offset maintenance and
repairs expense resulting from 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
$1.4 million (5.6%) during 1999, compared to 1998, due to
increased levels of plant and equipment placed in service. Total
income taxes decreased approximately $0.3 million (2.0%) during
1999 due primarily to lower taxable income during the current
year. See Note 9 of "Notes to Financial Statements" under Item 8
for additional information regarding income taxes. Other taxes
were up approximately $1.1 million (8.8%) during the year largely
as a result of increased property taxes.
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%) during 1998, due
primarily to the increased generation from 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. Natural gas prices were lower by 3.0% during 1998
as compared to 1997, helping to offset some of the additional
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 on 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 can be attributed
to 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.
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 9 of "Notes to Financial Statements" under Item 8
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 taxes.
Nonoperating Items
Total allowance for funds used during construction ("AFUDC")
amounted to approximately 6.1% of earnings applicable to common
stock during 1999, 1.6% during 1998, and 5.7% during 1997. AFUDC
increased significantly during 1999 reflecting higher levels of
construction work in progress related to the State Line Project.
AFUDC decreased significantly during 1998 reflecting lower levels
of construction work in progress due mainly to the completion of
State Line Unit No. 2 in June 1997. See Note 1 of "Notes to
Financial Statements" under Item 8.
Interest charges on long-term debt increased in both 1999 and
1998 due to the issuance of $100 million of the Company's
unsecured Senior Notes in November 1999 and $50 million of the
Company's First Mortgage Bonds in April 1998. The proceeds from
the Senior Notes were added to the Company's general funds and
were used to repay short-term indebtedness, including
approximately $33.1 million in commercial paper incurred in
connection with the Company's preferred stock redemption on August
2, 1999, as well as that incurred in connection with the Company's
construction program. The proceeds from the Company's First
Mortgage Bonds were added to the Company's general funds and 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. Commercial paper interest increased $1.0 million
(153.6%) during 1999 due to increased usage of short-term debt for
financing purposes, particularly in connection with the Company's
preferred stock redemption. Interest income for that year also
increased, reflecting the higher balances of cash available for
investment.
Earnings
Basic and diluted earnings per weighted average share of
common stock were $1.13 during 1999 compared to $1.53 in 1998.
Earnings per share were down primarily due to the $5.8 million in
merger costs incurred during 1999, as well as the $1.3 million in
excess consideration paid on redemption of the Company's preferred
stock. Earnings for 1999 were also negatively impacted by mild
temperatures and increased interest expense. Excluding the $5.8
million in merger costs, earnings per share would have been $1.46.
Earnings per 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 increase 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.
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 and Arkansas are the only
states in which the Company operates that have taken any such
action.
In Missouri, the Public Service Commission adopted an order in
1997 establishing a docket and creating a task force on retail
electric competition. The Commission Task Force, on which the
Company was represented, was charged with preparing a
comprehensive report for the Commission on how Missouri could
implement retail electric competition. The Joint Committee of the
Missouri Legislature received testimony during 1997 and 1998. No
legislative action was taken in 1999. There are bills pending in
the 2000 Missouri Legislature, but no action is expected this
year. In Kansas, although different bills have been introduced
into the House and Senate, no legislative action has been taken.
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. An Electric Utility Task Force has been studying all
issues in Oklahoma and has prepared legislation to provide a more
comprehensive framework for the transition to retail open access.
That legislation is under consideration by the Oklahoma General
Assembly. Approximately 3.1% of the Company's 1999 operating
revenue was derived from sales subject to Oklahoma regulation.
The Arkansas Legislature passed a bill in April 1999 that would
deregulate the state's electricity industry as early as January
2002. A special provision, however, applies to utilities with a
small portion of Arkansas customers whose majority of customers
are from another state. This provision, which applies to the
Company, exempts the Company from restructuring in Arkansas until
restructuring is enacted in Missouri or until January 1, 2004,
whichever comes first. The bill would freeze rates for three
years for residential and small business customers of utilities
that seek to recover stranded costs, and freeze rates for one year
for residential and small business customers of utilities, such as
the Company, that do not seek to recover stranded costs. This
freeze applies only to rate increases and does not apply to any
fuel adjustment clause or energy cost recovery rider approved by
the Arkansas Commission, such as the one the Company has to
recover its fuel and purchased power costs. The bill also
requires the unbundling of services on electric bills by June
2000. The Company is currently engaged in the regulatory
proceedings that have commenced as a result of the new law.
Approximately 2.6% of the Company's 1999 operating revenue was
derived from sales subject to Arkansas regulation.
In April 1996, the FERC issued Order No. 888 ("Order 888")
which required 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. Order 888
required a functional unbundling of transmission and power
marketing services. The Company and the SPP have filed open
access transmission tariffs covering these wholesale transmission
services. The SPP tariff applies to most of the transmission
services for which the Company tariff was designed. Where that is
the case, the Company shares revenues received from such
transmission services with other members of the SPP based on a
megawatt mile method of calculating transmission service charges.
There are, however, limited circumstances where the Company tariff
still applies and the Company receives 100% of the revenues from
the transmission services. The SPP tariff will continue to apply
unless and until a new tariff is filed as part of any regional
transmission organization ("RTO") which the Company may join as
discussed below.
On December 15, 1999, the FERC issued Order No. 2000 ("Order
2000"), which encourages the development of RTOs. RTOs are
designed to control the wholesale transmission services of the
utilities in its region. Order 2000 is intended to continue the
process of promoting open and more competitive markets in bulk
power sales of electricity that was begun with Order 888. On
December 30, 1999, SPP filed with the FERC for recognition as an
Independent System Operator and as an RTO. The Company does not
expect the implementation of Order 2000 to have a significantly
different impact on its results of operations than the
implementation of Order 888 and the operation of the SPP tariff
had.
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 1999,
the Company's retail rates were approximately 21% 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 wheeling. 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.
In addition, the Company has continued its investments in non-
regulated businesses which it commenced in 1996. The Company now
leases capacity on its broadband fiber optics network and provides
electronic monitored security, decorative lighting and other
energy services.
Year 2000 Costs
The Company experienced no Year 2000-related problems as it
passed from 1999 to 2000. The Company's total cost (which
includes the costs of a new financial management software package
and a new customer information system) to update all of its
systems for Year 2000 readiness was approximately $5.7 million, of
which approximately $5.1 million was capitalized while $0.6
million was expensed. Of these capitalized costs, $0.5 million
was included in the 1998 capital budget and $1.5 million was
included in the 1999 capital budget. Costs for specific Year 2000
remediation projects were charged to expense while costs to
replace software for business purposes other than addressing Year
2000 issues were capitalized.
LIQUIDITY AND CAPITAL RESOURCES
The information discussed below in this section is presented
without giving any effect to the Company's proposed merger with
UtiliCorp.
The Company's construction-related expenditures totaled
approximately $71.9 million, $51.9 million, and $56.7 million in
1999, 1998 and 1997, respectively.
A breakdown of the Company's 1999 construction expenditures
is as follows:
Construction Expenditures
(amounts in millions)
1999
New construction - State Line
Combined Cycle Unit 28.1
Distribution and transmission system
additions 24.6
Combustion turbine improvements and
upgrades 5.3
Additions and replacement - Asbury
and Riverton 5.0
Capitalized software costs 2.5
Fiber optics 0.5
General and other additions 5.9
Total $ 71.9
Approximately 46% of construction expenditures and other
funds requirements for 1999 were satisfied internally from
operations.
The Company estimates that its construction expenditures will
total approximately $105.7 million in 2000, $61.1 million in 2001
and $50.9 million in 2002. Of these amounts, the Company
anticipates that it will spend $21.4 million, $23.1 million and
$24.5 million in 2000, 2001 and 2002, respectively, for additions
to the Company's distribution system to meet projected increases
in customer demand. These construction expenditure estimates also
include approximately $57.8 million, $17.8 million and $3.5
million in 2000, 2001 and 2002 respectively, for the construction
of the State Line Combined Cycle Unit.
The total cost of construction at the State Line Combined
Cycle Unit is estimated to be $185 million. The Company's share of
this amount, after the transfer to WGI of an undivided 40% joint
ownership interest in the existing State Line Unit No.2 and
certain other property at book value is expected to be
approximately $100 million. For more information on the State Line
Project see Item 2, "Properties - Electric Facilities."
WGI is responsible for 40% of expenditures made by the
Company in connection with the construction and operation of the
State Line Combined Cycle Unit. In addition, WGI will continue to
make monthly prepayments to the Company for the future transfer of
its 40% joint ownership interest in the existing State Line Unit
No. 2, as well as an interest in certain underlying and
surrounding land and other property and equipment now owned by the
Company. These prepayments are reflected in State Line advance
payments on the balance sheet. See Item 8, "Financial Statements
and Supplementary Data."
The Company estimates that internally generated funds will
provide at least 50% of the funds required in 2000, 2001 and 2002
for estimated construction expenditures. As in the past, the
Company intends to utilize short-term debt to finance the
additional amounts needed for such construction and repay such
borrowings with the proceeds of 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 and from internally-generated
funds. The Company will continue to utilize short-term debt as
needed to support normal operations or other temporary
requirements and has a $50 million line of credit. See Note 6 of
"Notes to Financial Statements" regarding the Company's line of
credit. The Company financed its preferred stock redemption on
August 2, 1999 with approximately $33.1 million in commercial
paper. After redeeming all of its preferred stock, the Company is
no longer restricted by its Articles as to the amount of unsecured
indebtedness that it may have outstanding at any one time.
As a result of the implementation of and transition to the
Company's new Centurion customer information system, the Company
has experienced some delays in customer billing and cash
collection. The Company is working to correct these delays and is
continuing to enhance and refine this system.
The Company filed a shelf registration statement with the
SEC, which became effective on September 30, 1999, registering up
to an aggregate of $150 million of its common stock, first
mortgage bonds and unsecured debt securities. On November 19,
1999, the Company issued $100 million aggregate principal amount
of its unsecured Senior Notes, the net proceeds of which were
added to the Company's general funds and were used to repay short-
term indebtedness, including indebtedness incurred in connection
with the Company's preferred stock redemption and in connection
with the Company's construction program.
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.
Following announcement of the Merger, the ratings for the
Company's debt securities (other than the 5.20% Pollution Control
Series due 2013 and the 5.30% Pollution Control Series due 2013)
were placed on credit watch with downward implication by each of
Moody's Investors Service, Standard & Poor's and Duff & Phelps
Credit Rating Company. As of December 31, 1999, the Company's
ratings for its first mortgage bonds, senior notes and commercial
paper were as follows:
Phoenix
Duff & Phelps Moody's Standard & Poor's
First Mortgage A+ A2 A-
Bonds
First Mortgage
Bonds - Pollution AAA Aaa AAA
Control Series
Senior Notes A A3 Not Rated
Commercial Paper D-1 P-1 A-2
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 and commercial paper. 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 6 and 7 of "Notes to Financial
Statements" under Item 8 for further information.
If market interest rates average 1% more in 2000 than in
1999, the Company's interest expense would increase and income
before taxes would decrease by $300,000. This amount has been
determined by considering the impact of the hypothetical interest
rates on the Company's average daily commercial paper balances for
the year ended December 31, 1999. 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
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(a)(1) on page 44 present fairly, in all
material respects, the financial position of The Empire District
Electric Company at December 31, 1999 and 1998, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States. In addition,
in our opinion, the financial statement schedules listed in the
index appearing under Item 14(a)(2) on page 44 present fairly, in
all material respects, the information set forth therein when read
in conjunction with the related financial statements. These
financial statements and financial statement schedules are the
responsibility of the Company's management; our responsibility is
to express an opinion on these financial statements and financial
statement schedules based on our audits. We conducted our audits
of these statements in accordance with auditing standards
generally accepted in the United States, 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
February 2, 2000
Balance Sheet
December 31,
1999 1998
Assets
Utility plant, at original cost:
Electric
$ 871,263,673 $ 832,484,754
Water 7,023,246 6,398,086
Construction work in progress 41,712,243 16,701,068
919,999,162 855,583,908
Accumulated depreciation 303,951,518 283,337,538
616,047,644 572,246,370
Current assets:
Cash and cash equivalents 20,778,856 2,492,716
Accounts receivable - trade, net 17,377,963 13,645,641
Accrued unbilled revenues 6,660,318 6,218,889
Accounts receivable - other 6,726,734 1,590,536
Fuel, materials and supplies 15,978,790 15,704,678
Prepaid expenses 1,129,021 929,447
68,651,682 40,581,907
Noncurrent assets and deferred
charges:
Regulatory assets 37,075,852 35,999,139
Unamortized debt issuance costs 4,175,240 3,660,800
Other 5,458,466 805,568
46,709,558 40,465,507
Total Assets $ 731,408,884 $ 653,293,784
Capitalization and Liabilities
Common stock, $1 par value,
20,000,000 shares
authorized, 17,369,855 and
17,108,799 shares issued and
outstanding, $ 17,369,855 $ 17,108,799
Capital in excess of par value 163,909,731 156,975,596
Retained earnings 52,908,432 55,706,779
Total common 234,188,018 229,791,174
stockholders' equity
Preferred stock - 32,634,263
Long-term debt 345,850,169 246,092,905
580,038,187 508,518,342
Current liabilities:
Accounts payable and accrued 25,232,221 17,096,272
liabilities
Commercial paper - 14,500,000
Customer deposits 3,686,691 3,438,987
Interest accrued 5,026,356 4,113,300
33,945,268 39,148,559
Commitments and Contingencies (Note 11)
Noncurrent liabilities and deferred
credits:
Regulatory liability 15,295,992 16,400,125
Deferred income taxes 78,913,545 73,760,362
Unamortized investment tax 7,811,000 8,391,000
credits
Postretirement benefits other 4,592,721 4,463,883
than pensions
State Line advance payments 7,895,241 -
Other 2,916,930 2,611,513
117,425,429 105,626,883
Total
Capitalization and Liabilities $ 731,408,884 $ 653,293,784
The accompanying notes are an integral part of these financial statements.
Statement of Income
Year ended December 31, 1999
1999 1998 1997
Operating revenues:
Electric $241,065,202 $238,800,831 $214,306,599
Water 1,096,338 1,057,460 1,004,245
242,161,540 239,858,291 215,310,844
Operating revenue deductions:
Operating expenses:
Fuel 45,251,427 41,876,064 36,110,575
Purchased power 44,696,792 47,572,541 47,132,885
Merger related expenses 5,772,292 - -
Other 31,833,132 31,972,081 30,646,485
127,553,643 121,420,686 113,889,945
Maintenance and repairs 16,345,268 17,522,871 12,843,508
Depreciation and 26,366,695 24,980,637 23,395,291
amortization
Provision for income taxes 15,862,429 16,190,000 13,000,000
Other taxes 13,457,782 12,372,321 11,219,730
199,585,817 192,486,515 174,348,474
Operatingincome 42,575,723 47,371,776 40,962,370
Other income and deductions:
Allowance for equity funds
used during construction 56,845 8,938 150,524
Interest income 503,355 263,801 130,685
Other - net (662,118) (840,557) (453,127)
(101,918) (567,818) (171,918)
Income before 42,473,805 46,803,958 40,790,452
interest charges
Interest charges:
Long-term debt 19,402,734 17,873,833 16,593,042
Allowance for borrowed funds used
during construction (1,135,776) (400,044) (1,075,465)
Other 2,036,708 1,006,831 1,479,896
20,303,666 18,480,620 16,997,473
Net income 22,170,139 28,323,338 23,792,979
Preferred stock 1,403,025 2,411,784 2,416,340
dividend requirements
Excess consideration on
redemption of preferred stock 1,304,504 - -
Net income $ 19,462,610 $ 25,911,554 $ 21,376,639
applicable to
common stock
Weighted average number of
common shares outstanding 17,237,805 16,932,704 16,599,269
Basic and diluted earnings
per weighted average share
of common stock $ 1.13 $ 1.53 $ 1.29
Dividends per share of
common stock $ 1.28 $ 1.28 $ 1.28
Statement of Common Stockholder's Equity
Year ended December 31, 1999
1999 1998 1997
Common stock, $1 par value:
Balance, beginning of year $ 17,108,799 $16,776,654 $16,436,559
Stock/stock units issued
through:
Dividend reinvestment and
stock
purchase plan 223,910 259,267 299,134
Employee benefit plans 30,404 35,915 40,961
Director retirement plan 6,742 36,963 -
Balance, end of year $ 17,369,855 $17,108,799 $16,776,654
Capital in excess of par value:
Balance, beginning of year $156,975,596 150,784,239 145,313,610
Excess of net proceeds over
par value of stock issued:
Stock plans 6,685,989 6,188,030 5,470,404
Installments received on common
stock/stock purchase, net 248,146 3,327 225
Balance, end of year $163,909,731 156,975,596 150,784,239
Retained earnings:
Balance, beginning of year $ 55,706,779 51,472,897 51,340,554
Net income 22,170,139 28,323,338 23,792,979
77,876,918 79,796,235 75,133,533
Less dividends paid:
8 1/8% preferred stock 1,349,474 2,027,390 2,031,250
5% preferred stock 124,642 195,090 195,090
4 3/4% preferred stock 126,094 190,000 190,000
Common stock 22,063,772 21,676,976 21,244,296
23,663,982 24,089,456 23,660,636
Less: excess consideration
on redemption of preferred 1,304,504 - -
stock
Balance, end of year $ 52,908,432 $55,706,779 $51,472,897
Statement of Cash Flows
Year ended December 31,
1999 1998 1997
Operating activities
Net income $ 22,170,139 $28,323,338 $23,792,979
Adjustments to reconcile net
income to cash flows:
Depreciation and 29,672,416 28,323,595 26,510,852
amortization
Pension income (4,325,229) (2,239,850) (725,199)
Deferred income taxes, net 4,480,000 3,390,000 2,800,000
Investment tax credit, net (580,000) (580,000) (590,000)
Allowance for equity funds
used
during construction (56,845) (8,938) (150,524)
Issuance of common stock
for
401(k) plan 753,203 702,801 660,162
Issuance of common stock
units for
director retirement plan 84,000 711,000 -
Other - 66,955 129,259
Cash flows impacted by
changes in:
Accounts receivable and
accrued
unbilled revenues (9,309,949) (584,001) 1,132,283
Fuel, materials and (274,112) (2,489,610) 1,220,673
supplies
Prepaid expenses and
deferred charges (3,050,794) 2,431,806 (324,242)
Accounts payable and
accrued liabilities 8,135,949 2,233,691 255,402
Customer deposits,
interest
and taxes accrued
971,596 84,941 741,425
Other liabilities and
other deferred credits 8,329,496 (1,883,100) (459,232)
Net cash provided by
operating activities 56,999,870 58,482,628 54,993,838
Investing activities
Construction expenditures (71,935,978)(51,917,153)(56,673,275)
Allowance for equity funds used
during construction 56,845 8,938 150,524
Net cash used in (71,879,133)(51,908,215)(56,522,751)
investing activities
Financing activities
Proceeds from issuance of
first mortgage bonds $ - $49,672,000 $ -
Proceeds from issuance of 99,818,000 - -
senior notes
Proceeds from issuance of
common stock 6,357,989 5,109,701 5,150,561
Redemption of preferred (32,634,263) - -
stock
Reacquired preferred stock - (267,537) -
Excess consideration on redemption of
preferred stock (1,304,504) - -
Dividends (23,663,982)(24,089,456)(23,660,636)
Repayment of first mortgage (110,000)(23,000,000) (165,000)
bonds
Net proceeds (repayments) from
short-term borrowings (14,500,000)(13,500,000) 20,500,000
Payment of debt issue costs (797,837) (551,687) 3,134
Net cash (used in)/provided by
financing activities 33,165,403 (6,626,979) 1,828,059
Net increase (decrease) in cash
and cash equivalents 18,286,140 (52,566) 299,146
Cash and cash equivalents,
beginning of year 2,492,716 2,545,282 2,246,136
Cash and cash equivalents, end of year
$ 20,778,856 $ 2,492,716 $ 2,545,282
Cash and cash equivalents include cash on hand and temporary
investments purchased with an initial maturity of three months or
less. Interest paid was $19,301,000, $17,439,000, $17,123,000 for
the years ended December 31, 1999, 1998 and 1997, respectively.
Income taxes paid were $12,221,000, $14,088,000 and $10,250,000
for the years ended December 31, 1999, 1998 and 1997,
respectively.
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 Commission (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 1999 were derived as follows:
residential 41%, commercial 31%, industrial 17%, wholesale 4%
and other 7%. 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%, 3.2% and 3.1% of depreciable property for
1999, 1998 and 1997, 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 1999, 1998 and 1997 periods was 17,237,805,
16,932,704 and 16,599,269, respectively. Dilutive stock
options for the 1999, 1998 and 1997 periods were 5,290,
7,775 and 9,844, 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 5.4% for 1999, 5.9% for
1998 and 6.4% for 1997 (on a before-tax basis) compounded
semiannually.
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
$372,000 at December 31, 1999 and $276,000 at December 31,
1998.
Franchise taxes
Franchise taxes are collected for and remitted to their
respective cities. Operating revenues include franchise
taxes of $4,400,000, $4,400,000 and $3,900,000 for each of
the years ended December 31, 1999, 1998 and 1997,
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.
State Line advance payments
The Company is currently receiving advance payments from
Westar Generating, Inc. (WGI) for WGI's share of the existing
State Line facility (See Note 10).
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 period. Actual
amounts could differ from those estimates.
2. Merger Agreement
The Company and UtiliCorp United, Inc., a Delaware
corporation ("UtiliCorp"), have entered into an Agreement and
Plan of Merger, dated as of May 10, 1999 (the "Merger
Agreement"), which provides for a merger of the Company with
and into UtiliCorp, with UtiliCorp being the surviving
corporation (the "Merger"). Under the terms of the Merger
Agreement, UtiliCorp is offering $29.50 for each share of
common stock of the Company, payable in UtiliCorp common
stock or cash. The Merger Agreement contains a collar
provision under which the value of the Merger consideration
per share will decrease if UtiliCorp's common stock is below
$22 per share preceding the closing and will increase if
UtiliCorp's common stock is above $26 per share preceding the
closing. Stockholders of the Company may elect to take cash
or stock, but total cash paid to stockholders will be limited
to no more than 50% of the total Merger consideration, and
the UtiliCorp common stock that may be issued in the Merger
is limited to 19.9% of the then outstanding common stock of
UtiliCorp. UtiliCorp also will become liable for all of the
Company's existing debt, including its first mortgage bonds.
The Merger, which was unanimously approved by the Boards of
Directors of the constituent companies, is expected to close
after all of the conditions to the consummation of the Merger
are met or waived. The Merger is conditioned, among other
things, upon approval of stockholders of the Company,
approvals of federal regulatory agencies and approvals of
state regulatory authorities in states where the combined
company will operate. Other conditions in the Merger
Agreement require the Company to redeem all of its
outstanding preferred stock according to its terms prior to
the closing and to obtain the consent of holders of its
outstanding first mortgage bonds to a modification of a
dividend limitation provision relating to successor
corporations which is contained in the Company's indenture of
Mortgage and Deed of Trust, dated as of September 1, 1944, as
amended and supplemented (the "Mortgage"), pursuant to which
its first mortgage bonds are issued.
The Company has received the requisite consents to amend the
dividend limitation in its Mortgage and has entered into a
supplemental indenture in order to implement that amendment.
The supplemental indenture will not become effective and no
consent fee will be paid, however, until the Merger is
completed. On August 2, 1999, the Company redeemed all of
its outstanding preferred stock for approximately
$34,200,000. In addition, the Company called a special
meeting of stockholders on September 3, 1999, for the purpose
of voting on the proposed Merger with UtiliCorp. The Merger
proposal passed with 76.3% of the Company's outstanding
shares being voted in favor of the proposal. UtiliCorp is
not required to obtain its stockholders' approval of the
Merger.
3. Regulatory Matters
During the three years ending December 31, 1999, the
following rate changes were requested or in effect:
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, 1998, and the
Company received an order from the Arkansas Commission on
July 21, 1998 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%.
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 which are being amortized over periods
of up to 25 years:
1999 1998
Regulatory Assets
Income taxes $ 24,236,009 $ 24,666,959
Unamortized loss on reacquired debt 8,811,488 9,352,691
Asbury five year maintenance 894,567 1,526,029
Other postretirement benefits 421,075 453,460
Coal contract restructuring costs 1,882,941 -
Gas supply realignment costs 829,773 -
Total Regulatory Assets $ 37,075,853 $ 35,999,139
Regulatory Liability
Income taxes $ 15,295,992 $ 16,400,125
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.
Deregulation
If and when retail electric competition legislation is passed
in the states the Company serves, the Company may determine
that it no longer meets the criteria set forth in SFAS 71
with respect to continued recognition of some or all of the
regulatory assets and liabilities. Any regulatory changes
that would require the Company to discontinue application of
SFAS 71 based upon competitive or other events may also
impact the valuation of certain utility plant investments.
Impairment of regulatory assets or utility plant investments
could have a material adverse effect on the Company's
financial condition and results of operations.
In Missouri, the Public Service Commission adopted an order
in 1997 establishing a docket and creating a task force on
retail electric competition. The Commission Task Force, on
which the Company was represented, was charged with preparing
a comprehensive report for the Commission on how Missouri
could implement retail electric competition. The Joint
Committee of the Missouri legislature received testimony
during 1997 and 1998. No legislative action was taken in
1999. There is a bill pending in the 2000 Missouri
legislature, but no action is expected until 2001. In
Kansas, although different bills were introduced into the
House and Senate during 1997, no legislative action has been
taken.
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. None of the
Company's plant investment or regulatory assets were
considered impaired as a result of the bill.
The Arkansas Legislature passed a bill in April 1999 that
would deregulate the state's electricity industry as early as
January 2002. A special provision however, applies to
utilities with a small portion of Arkansas revenues whose
majority of revenues are from another state. This provision
which applies to the Company exempts the Company from
restructuring in Arkansas until restructuring is enacted in
Missouri or until January 1, 2004, whichever comes first.
The bill would freeze rates for three years for residential
and small business customers of utilities, such as the
Company, that do not seek to recover stranded costs. This
freeze applies only to rate increases and does not apply to
any fuel adjustment clause or energy cost recovery rider
approved by the Arkansas Commission, such as the one the
Company has to recover its fuel and purchased power costs.
The bill also requires the unbundling of services on electric
bills by June 2000. The Company is currently engaged in the
regulatory proceedings that have commenced as a result of the
new law. None of the Company's plant investment or
regulatory assets were considered impaired as a result of the
bill.
4. Common Stock
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
1999, 3,442 units were granted under the Director Retirement
Plan and 2,154 units were granted pursuant to the stock
incentive 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 63,985 shares at
$23.35, 50,368 shares at $18.34 and 58,972 shares at $15.53
on December 31, 1999, 1998 and 1997, respectively. Shares
were issued at $18.34 per share in 1999, $15.53 per share in
1998, and $15.64 per share in 1997. The Company is in the
process of amending the Employee Stock Purchase Plan in order
to extend the termination date to May 31, 2003.
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 February 1999 and January 1998 and 1997, grants for
1,144, 1,535 and 1,414 shares, respectively, of restricted
stock were made to qualified employees under the Stock
Incentive Plan. For grants made to date, the restrictions
typically lapse and the shares are issuable to employees who
continue 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 1999,
1998 and 1997, 3,300, 2,641 and 3,983 shares, respectively,
were issued under the Stock Incentive Plan. No options 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
1999 and 1998 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 30,919, 32,274
and 36,978 shares of common stock in 1999, 1998 and 1997,
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, 1999, 1,294,062 shares remain available for
issuance under the foregoing plans.
5. Preferred Stock
The Company 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.
The Company has 5,000,000 shares of $10.00 par value
cumulative preferred stock authorized.
Of this amount, preferred stock without mandatory redemption
provisions issued and outstanding at December 31, 1999 and
1998 is as follows:
1999 1998
5% cumulative (400,000 shares 381,820
authorized) -
4 3/4% cumulative (400,000 shares - 400,000
authorized)
8 1/8% cumulative (2,500,000 shares - 2,480,998
authorized)
- 3,262,818
On August 2, 1999 the Company redeemed all outstanding 5%,
4 3/4%, and 8 1/8% series of cumulative preferred stock. Holders
were paid 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).
Preference Stock Purchase Rights
The Company had 8,663,648 and 8,535,918 Preference Stock
Purchase Rights (Rights) outstanding at December 31, 1999 and
1998, 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. The provisions of the
Rights were amended in 1999 to exclude the pending merger
with UtiliCorp United, Inc.
6. 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, 1999 the long-term debt outstanding was as
follows:
1999 1998
First mortgage bonds:
71/2% Series due 2002 $37,500,000 $37,500,000
7.60% Series due 2005 10,000,000 10,000,000
81/8% Series due 2009 (1) 20,000,000 20,000,000
61/2% Series due 2010 50,000,000 50,000,000
7.20% Series due 2016 25,000,000 25,000,000
93/4% Series due 2020 2,250,000 2,250,000
7% Series due 2023 45,000,000 45,000,000
73/4% Series due 2025 30,000,000 30,000,000
71/4% Series due 2028 13,616,000 13,726,000
5.3% Pollution Control Series 8,000,000 8,000,000
due 2013
5.2% Pollution Control Series 5,200,000 5,200,000
due 2013
246,566,000 246,676,000
Senior Notes, 7.70% Series 100,000,000 -
due 2004
Less unamortized net discount (715,831) (583,095)
$345,850,169 $246,092,905
(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
$346,566,000 and $246,676,000 at December 31, 1999 and 1998,
respectively, and its fair market value was estimated to be
approximately $329,118,000 and $252,155,000, 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, 1999, the Company had a $50,000,000 unsecured
line of credit. Borrowings are at the bank's prime
commercial rate and are due 370 days from the date of each
loan. The Company also had a $25,000,000 unsecured line of
credit at December 31, 1999, bearing interest at 30-day LIBOR
plus .75%. This unsecured line of credit expired on January
31, 2000. These arrangements do not serve to legally
restrict the use of the Company's cash. The lines of credit
are also utilized to support the Company's issuance of
commercial paper although they are not assigned specifically
to such support. There were no outstanding borrowings under
these agreements at December 31, 1999 or 1998.
On November 18, 1999, the Company sold to the public in an
underwritten offering $100 million aggregate principal amount
of its Senior Notes, 7.70% Series due 2004. The net proceeds
of this sale were added to the Company's general funds and
were used to repay short-term indebtedness, including
indebtedness incurred in connection with the redemption of
the Company's preferred stock and the Company's construction
program.
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, 1999 and to
repay short-term indebtedness, including indebtedness
incurred in connection with the Company's construction
program.
7. Short-term Borrowings
Short-term commercial paper outstanding and notes payable
averaged $30,796,000 and $11,274,000 daily during 1999 and
1998, respectively, with the highest month-end balances being
$65,000,000 and $28,500,000, respectively. The weighted
daily average interest rates during 1999, 1998 and 1997 were
5.4%, 5.9% and 5.9%, respectively. The weighted average
interest rates of borrowings outstanding at December 31, 1999
and 1998 were, 6.12% and 6.2%, respectively.
8. Retirement Benefits
Pensions
In 1998, the Company adopted Statement of Financial
Accounting Standards (SFAS) 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits," which
resulted in revisions to the 1997 information previously
reported.
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:
1999 1998 1997
Benefit obligation at beginning
of year $ 77,285,598 $ 78,360,097 $ 66,805,630
Service cost 2,516,067 2,400,303 2,095,442
Interest cost 5,368,097 5,046,012 4,956,356
Amendments 1,744,656 - (277,808)
Actuarial (10,076,097) (4,065,095) 9,251,195
(gain)/loss
Benefits paid (4,550,197) (4,455,719) (4,470,718)
Benefit obligation at end
of year $ 72,288,124 77,285,598 78,360,097
1999 1998 1997
Fair value of plan assets at
beginning of year $ 93,153,901 $ 82,106,242 $ 70,970,880
Actual return on 15,882,138 15,503,378 15,606,080
plan assets
Benefits paid (4,550,197) (4,455,719) (4,470,718)
Fair value of plan assets
at end of year $ 104,485,842 93,153,901 82,106,242
Funded status $ 32,197,718 $ 15,868,303 $ 3,746,145
Unrecognized net assets at
January 1, 1986 being amortized
over 17 years (1,473,468) (1,964,623) (2,455,778)
Unrecognized 4,786,072 3,560,847 3,964,146
prior service cost
Unrecognized (31,683,391) (18,028,407) (8,058,243)
net gain
Prepaid/(accrued) pension cost $ 3,826,931 $ (563,880) $ (2,803,730)
Assumptions used in calculating the projected benefit
obligation for 1999 and 1998 include the following:
1999 1998 1997
Weighted average 8.00% 7.00% 6.75%
discount rate
Rate of increase 5.50% 5.50% 5.50%
in compensation
levels
Expected 9.00% 9.00% 9.00%
long-term rate of
return on plan assets
Net pension benefit for 1999, 1998 and 1997 is comprised of
the following components:
1999 1998 1997
Service cost - benefits earned
during the period $ 2,516,067 $ 2,400,303 $ 2,095,442
Interest cost on projected
benefit obligation 5,368,097 5,046,012 4,956,356
Expected return on (8,323,982) (7,173,641) (6,169,097)
plan assets
Net amortization (3,950,993) (2,512,524) (1,607,900)
and deferral
Net pension benefit $ (4,390,811) $(2,239,850) $ (725,199)
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 $21,700,000) 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 $10,600,000 at
December 31, 1999 and $6,800,000 at December 31, 1998.
Postretirement benefits, a portion of which have been capitalized and/or
deferred, for 1999, 1998 and 1997 included the following components:
Service cost on benefits earned 1999 1998 1997
during the year $ 781,017 $ 558,983 $ 434,397
Interest cost on projected benefit
obligation 2,281,028 1,593,181 1,559,110
Return on assets (618,353) (375,581) (290,079)
Amortization of unrecognized
transition obligation 1,084,017 1,084,017 1,084,017
Unrecognized net 1,207,628 (720,744) (1,111,795)
(gain)/loss
Other - - (92,890)
Net periodic postretirement
benefit cost $4,735,337 $2,139,856 $1,582,760
The estimated funded status of the Company's obligations
under SFAS 106 at December 31, 1999, 1998 and 1997 using a
weighted average discount rate of 8.0%, 7.0% and 6.75%,
respectively, is as follows:
1999 1998 1997
Benefit obligation at
beginning of year $ 24,580,797 $ 23,978,240 $ 20,850,702
Service cost 781,017 558,983 434,397
Interest cost 2,281,028 1,593,181 1,559,110
Acturial (gain)/loss 2,227,896 (353,055) 2,080,611
Benefits paid (1,201,710) (1,196,552) (946,580)
Benefit obligation at $ 28,669,028 $ 24,580,797 $ 23,978,240
end of year
Fair value of plan assets at
beginning of year $ 6,803,302 $ 5,691,142 $ 4,829,610
Employer contributions 4,604,982 2,102,087 1,518,033
Actual return on 345,870 206,625 290,079
plan assets
Benefits paid (1,201,710) (1,196,552) (946,580)
Fair value of plan assets
at end of year $ 10,552,444 $ 6,803,302 $ 5,691,142
Funded status $(18,116,584) $ (17,777,495) (18,287,098)
Unrecognized transition 14,092,208 15,176,225 16,260,242
obligation
Unrecognized net gain (494,279) (1,787,030) (2,323,675)
Accrued postretirement
benefit cost $ (4,518,655) $ (4,388,300) $ (4,350,531)
The assumed 2000 cost trend rate used to measure the expected
cost of healthcare benefits is 7.5%. The trend rate
decreases through 2005 to an ultimate rate of 6% for 2006 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 $3,100,000 to
$3,800,000 and the accumulated postretirement benefit
obligation from $28,700,000 to $34,500,000.
9. Income Taxes
The provision for income taxes is different from the amount
of income tax determined by applying the statutory income tax
rate to income before income taxes as a result of the
following differences:
1999 1998 1997
Computed "expected"
federal provision $ 13,360,000 $ 15,480,000 $ 12,825,000
State taxes, net of
federal effect 1,180,000 1,370,000 930,000
Adjustment to taxes
resulting from:
Nondeductible merger 2,200,000 - -
costs
Investment tax credit
amortization (580,000 (580,000) (590,000)
Other (160,000) (370,000) (315,000)
Actual provision $ 16,000,000 $ 15,900,000 $ 12,850,000
Income tax expense components for the years shown are as
follows:
1999 1998 1997
Taxes currently payable
Included in operating
revenue deductions:
Federal $ 10,761,000 $ 12,110,000 $ 9,830,000
State 1,329,000 1,430,000 960,000
Included in "other - net" 10,000 (290,000) (150,000)
12,100,000 13,250,000 10,640,000
Deferred taxes
Depreciation and
amortization differences 3,018,000 3,077,000 3,210,000
Loss on reacquired debt (206,000) (213,000) (227,000)
Postretirement benefits 928,000 528,000 159,000
Other (17,000) (454,000) (542,000)
Asbury five year (241,000) (241,000) 200,000
maintenance
Software development 998,000 533,000 -
costs
Deferred investment tax
credits, net (580,000) (580,000) (590,000)
Total income tax $ 16,000,000 $ 15,900,000 $ 12,850,000
expense
Under SFAS 109, temporary differences gave rise to deferred
tax assets and deferred tax liabilities at year end 1999 and
1998 as follows:
Balances as of December 31,
1999 1998
Deferred Deferred Deferred Deferred
Tax Tax Tax Tax
Assets Liabilities Assets Liabilities
Noncurrent
Depreciation and other
property $ 10,630,457 $ 91,009,149 $ 11,296,127 $ 88,422,060
related
Unamortized investment
tax credits 4,910,498 - 5,275,124 -
Miscellaneous
book/tax
recognition
differences 3,561,786 7,007,137 4,471,137 6,380,690
Total deferred $ 19,102,741 $ 98,016,286 $ 21,042,388 $ 94,802,750
taxes
10. Commonly Owned Facilities
The Company owns a 12% undivided interest in the Iatan Power
Plant, 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,
1999 and 1998, the Company's property, plant and equipment
accounts include the cost of its ownership interest in the
unit of $44,656,000 and $44,628,000, respectively, and
accumulated depreciation of $28,689,000 and $27,045,000,
respectively.
On July 26, 1999, the Company and Westar Generating, Inc.
("WGI"), a subsidiary of Western Resources, Inc., entered
into agreements for the construction, ownership and operation
of a 500-megawatt combined cycle unit at the State Line Power
Plant (the "State Line Combined Cycle Unit"). Work has begun
and the State Line Combined Cycle Unit is projected to be
operational by June 2001. The Company will own an undivided
60% interest in the State Line Combined Cycle Unit with WGI
owning the remainder. The Company is entitled to 60% of the
capacity of the State Line Combined Cycle Unit. The Company
will contribute its existing 152-megawatt State Line Unit No.
2 combustion turbine to the State Line Combined Cycle Unit,
and as a result, upon commercial operation, the State Line
Combined Cycle Unit will provide the Company with
approximately 150 megawatts of additional capacity. The
total cost of the State Line Combined Cycle Unit is estimated
to be $185,000,000. The Company's share of this amount,
after the transfer to WGI of an undivided 40% joint ownership
interest in the existing State Line Unit No. 2 and certain
other property at book value, is expected to be
approximately $100,000,000. The Company and WGI are
responsible for their own financing of the project and the
Company is billing WGI for its share of monthly construction
costs as well as advance payments for WGI's share of the
existing State Line Unit No. 2 combustion turbine.
11. Commitments and Contingencies
The Company's 2000 construction budget is $105,720,000. The
Company's five-year construction program for 2000 through
2004 is estimated to be approximately $319,555,000.
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 $50,000,000, $64,000,000 and $55,000,000 in
1999, 1998 and 1997, 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 $32,000,000 in 2000, $30,000,000 in 2001,
$26,000,000 in 2002 and 24,000,000 in 2003 and reducing to
lesser amounts thereafter through 2012.
12. Selected Quarterly Information (Unaudited)
A summary of operations for the quarterly periods of 1999 and
1998 is as follows:
Quarters
First Second Third Fourth
(dollars in thousands except per share amounts)
1999:
Operating revenues $ 54,742 $ 53,309 $ 81,460 $ 52,650
Operating income 10,004 5,022 17,995 9,556
Net income 5,238 302 13,004 3,626
Net income applicable
to common stock 4,639 (295) 11,493 3,626
Basic and diluted
earnings per average
share of common
stock $ .27 $ (.02) $ .66 $ .21
First Second Third Fourth
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
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 27, 2000, 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 27, 2000, 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
27, 2000, 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 27, 2000, 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, 1999 and 1998 24
Statements of income for each of the three years in the period 25
ended December 31, 1999
Statements of common stockholders' equity for each of the three
years in the period ended December 31, 26
1999
Statements of cash flows for each of the three years in the 27
period ended December 31, 1999
Notes to financial statements 28
Schedule for the years ended December 31, 1999, 1998 and 1997:
Schedule II - Valuation and qualifying accounts 46
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
(2) - Agreement and Plan of Merger, dated as of May 10, 1999, by
and between the Company and UtiliCorp United Inc.
(Incorporated by reference to Exhibit 2 to Form 10-Q for
quarter ended March 31, 1999, File No.1-3368).
(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) Thirtieth Supplemental Indenture dated as of July 1, 1999 to
Indenture of Mortgage and Deed of Trust (Incorporated by
reference to Exhibit 4 (a) to Form 10-Q for quarter ended
June 30, 1999, File No. 1-3368).
(r) - 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).
(s) - Amendment #1 to Rights Agreement dated October 24, 1991
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).
(t) - Amendment #2 to Rights Agreement dated May 10, 1999
(Incorporated by reference to Exhibit 4(b) to Form 10-Q for
quarter ended June 30, 1999, File No. 1-3368).
(10)(a) - 1996 Stock Incentive Plan (Incorporated by reference to
Exhibit 4.1 to Form S-8, File No. 33-64639).
(b) - 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).
(c) - Deferred Compensation Plan for Directors (Incorporated by
reference to Exhibit 10(d) to Annual Report on Form 10-K
for year ended December 31, 1990, File No. 1-3368).
(d) - The Empire District Electric Company Change in Control
Severance Pay Plan and Forms of Agreement (Incorporated by
reference to Exhibit 10 to Form 10-Q for quarter ended
September 30, 1991, File No. 1-3368).
(e) - Amendment to The Empire District Electric Company Change in
Control Severance Pay Plan and revised Forms of Agreement
(Incorporated by reference to Exhibit 10 to Form 10-Q for
quarter ended June 30, 1996, File No. 1-3368).
(f) - The Empire District Electric Company Supplemental Executive
Retirement Plan. (Incorporated by reference to Exhibit
10(e) to Annual Report on Form 10-K for year ended December
31, 1994, File No. 1-3368).
(g) Retirement Plan for Directors as amended August 1, 1998
(Incorporated by reference to Exhibit 10(a) to Form Q for
quarter ended September 30, 1998, File No. 1-3368).
(h) Stock Unit Plan for Directors (Incorporated by reference to
Exhibit 10(b) to Form Q for quarter ended September 30,
1998, File No. 1-3368).
(12) - Computation of Ratios of Earnings to Fixed Charges and
Earnings to Combined Fixed Charges and Preferred Stock
Dividend Requirements.*
(23) - Consent of PricewaterhouseCoopers LLP*
(24) - Powers of Attorney.*
(27) - Financial Data Schedule for December 31, 1999.
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 1999.
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 1999, 1998 and 1997
Balance Additions Deductions Balance
At Charged to Other Accounts from reserve at
Beginning close of
of Charged to period
period Income Description Amount Description Amount
Year ended
December 31, 1999:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written written
Uncollectible $ 275,876 $ 580,873 off $ 372,955 off $ 857,758 $ 371,946
accounts
Reserve not shown
separately in
balance sheet: Property, plant
Injuries and & equipment and Claims
damages Reserve clearing accounts and
(Note A) $1,314,461 $407,163 $ 407,163 expenses $1,128,787 $1,000,000
Year ended
December 31, 1998:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written written
Uncollectible $ 278,741 $586,000 off $ 448,718 off $1,037,583 $ 275,876
accounts
Reserve not shown
separately in
balance sheet: Property, plant Claims
Injuries and & equipment and and
damages Reserve clearing accounts expenses
(Note A) $1,311,995 $580,832 $ 530,011 $1,108,377 $1,314,461
Year ended
December 31, 1997:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written written
Uncollectibl $ 265,390 $486,000 off $332,632 off $ 805,281 $ 278,741
accounts
Reserve not shown
separately in
Balance sheet: Property, plant Claims
Injuries and & equipment and and
damages Reserve clearing accounts expenses
(Note A) $1,300,917 $484,541 $472,107 $ 945,570 $1,311,995
NOTE A: This reserve is provided for workers' compensation,
certain postemployment benefits and public liability damages. The
Company at December 31, 1999 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
M. W. MCKINNEY
By.............................
M.W. McKinney, President
Date: March 21, 2000
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 21, 2000
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)