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, 2000 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 X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
As of March 1, 2001, 17,608,466 shares of common stock were outstanding.
Based upon the closing price on the New York Stock Exchange on March 1,
2001, the aggregate market value of the common stock of the Company held
by nonaffiliates was approximately $356,571,437.
The following documents have been incorporated by reference into the
parts of the Form 10-K as indicated:
The Company's proxy statement, Part of Item 10 of Part III
filed pursuant To Regulation
14A under the Securities All of Item 11 of Part III
Exchange Act of 1934, for its
2000 Annual Meeting of Part of Item 12 of Part III
Stockholders to be held on
April 25, 2001. All of Item 13 of Part 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 Empire 8
Regulation 8
Environmental Matters 9
Conditions Respecting Financing 10
ITEM 2. PROPERTIES 11
Electric Facilities 11
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 13
STOCKHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL DATA 14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS 15
Terminated Merger With UtiliCorp 15
Results of Operations 15
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 43
FINANCIAL DISCLOSURE
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 48
FORWARD LOOKING STATEMENTS
Certain matters discussed in this quarterly report are
"forward-looking statements" intended to qualify for the safe
harbor from liability established by the Private Securities
Litigation Reform Act of 1995. Such statements address future
plans, objectives, expectations and events or conditions concerning
various matters such as capital expenditures (including those
planned in connection with the State Line Combined Cycle Unit),
earnings, competition, litigation, environmental compliance, 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 (including the continuation of significantly
increased natural gas prices); unexpected consequences resulting
from the unsuccessful 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
(including the outcome of the pending interim and permanent rate
cases seeking recovery of increased fuel and other costs and the
inclusion of the State Line Combined Cycle in the rate base) 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, a Kansas corporation
organized in 1909, is an operating public utility engaged in the
generation, purchase, transmission, distribution and sale of
electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. We
also provide water service to three towns in Missouri. In 2000,
99.6% of our gross operating revenues were provided from the sale
of electricity and 0.4% from the sale of water.
Empire and UtiliCorp United, Inc. entered into an Agreement
and Plan of Merger, dated as of May 10, 1999, which provided for
our merger with and into UtiliCorp, with UtiliCorp being the
surviving corporation. At a special meeting held on September 3,
1999, the merger was approved by our stockholders. The merger was
conditioned, among other things, upon approvals of various federal
and state regulatory agencies, with either company having the right
to terminate the merger agreement if all regulatory approvals were
not obtained by December 31, 2000. All approvals were not received
by this date and UtiliCorp notified us on January 2, 2001 that it
was terminating the merger agreement. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" for further information.
The territory served by our 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 light
industry, agriculture and tourism. Of our total 2000 retail
electric revenues, approximately 88% came from Missouri customers,
6% from Kansas customers, 3% from Oklahoma customers and 3% from
Arkansas customers.
We supply electric service at retail to 119 incorporated
communities and to various unincorporated areas and at wholesale to
four municipally-owned distribution systems and two rural electric
cooperatives. The largest urban area we serve is the city of
Joplin, Missouri, and its immediate vicinity, with a population of
approximately 144,000. We operate under franchises having original
terms of twenty years or longer in virtually all of the
incorporated communities. Approximately 50% of our electric
operating revenues in 2000 were derived from incorporated
communities with franchises having at least ten years remaining and
approximately 19% were derived from incorporated communities in
which our franchises have remaining terms of ten years or less.
Although our franchises contain no renewal provisions, in recent
years we have obtained renewals of all of our expiring electric
franchises prior to the expiration dates.
Our electric operating revenues in 2000 were derived as
follows: residential 42%, commercial 30%, industrial 16%, wholesale
8% and other 4%. Our largest single on-system wholesale customer
is the city of Monett, Missouri, which in 2000 accounted for
approximately 3% of electric revenues. No single retail customer
accounted for more than 1% of electric revenues in 2000.
We made an investment of approximately $1.9 million in 2000
and $0.5 million in 1999 in fiber optics cable and equipment which
we are using in our own operations and leasing to other entities.
We also offer electronic monitored security services, generators,
surge suppressors, decorative lighting and other energy services.
Electric Generating Facilities and Capacity
At December 31, 2000, our 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). We also have a
12% ownership interest (80 megawatt capacity) in Unit No. 1 at the
Iatan Generating Station. We are currently constructing a 350
megawatt expansion at the State Line Power Plant which will result
in a 500 megawatt combined-cycle unit (the "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 we will be entitled to approximately
150 megawatts of additional generating capacity. See Item 2,
"Properties - Electric Facilities" for further information about
these plants.
We are a member of the Southwest Power Pool, referred to as
SPP, a regional division of the North American Electric Reliability
Council (NERC), which requires its members to maintain a 12%
capacity margin and provides for contingency reserve sharing,
regional near real-time security assessment 24 hours per day and
many other functions. We are participating with other utility
members in the restructuring of the SPP to make it a regional
transmission organization (RTO). The SPP filed with the FERC on
December 30, 1999 for RTO status. This filing was rejected by the
FERC as not meeting certain requirements of its Order 2000. The
SPP filed a second request in the fourth quarter of 2000 addressing
the FERC's concerns and continuing to seek RTO status. The FERC has
not yet ruled on the modified filing. See Item 7, ""Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Competition."
We currently supplement our on-system generating capacity with
purchases of capacity and energy from other utilities in order to
meet the demands of our customers and the capacity margins
applicable to us under current pooling agreements and NERC rules.
We have entered into agreements for such purchases with Western
Resources and Southwestern Public Service Company (a subsidiary of
XCEL Energy) which terminate on May 31, 2001. In addition, we have
contracted with Western Resources for the purchase of capacity and
energy through May 31, 2010. The amount of capacity purchased under
these contracts supplements our on-system capacity and contributes
to meeting our current expectations of future power needs. The
following chart sets forth our purchase commitments and our
anticipated owned capacity (in megawatts) during the indicated
contract years (which run from June 1 to May 31 of the following
year). The reduction in purchased power commitments in 2001
reflects the May 31 termination of the contracts as described above
and the installation of additional generation from the State Line
Combined Cycle Unit scheduled to go into commercial operation in
June 2001. We currently expect to purchase additional capacity to
meet reserve margins in 2003 through 2005 of 30 to 100 megawatts
per year based on current forecast of load.
Purchased Anticipated
Contract Power Owned
Year Commitment Capacity Total
2000 287 878 1165
2001 162 1026 1188
2002 162 1026 1188
2003 162 1026 1188
2004 162 1026 1188
2005 162 1026 1188
The charges for capacity purchases under the contracts referred to
above during calendar year 2000 amounted to approximately $22.3
million. Minimum charges for capacity purchases under such
contracts total approximately $91.04 million for the period June 1,
2001, through May 31, 2006.
The maximum hourly demand on our system reached a new record
high of 993 megawatts on August 30, 2000. Our previous record peak
of 979 megawatts was established in August 1999. We set a new
maximum hourly winter demand of 941 megawatts on December 19, 2000.
Construction Program
Total gross property additions (including construction work in
progress) for the three years ended December 31, 2000, amounted to
$252.9 million, and retirements during the same period amounted to
$14.0 million.
Our total construction-related expenditures, including
allowance for funds used during construction, referred to as AFUDC,
were $131.8 million in 2000 and for the next three years are
estimated for planning purposes to be as follows:
Estimated Construction Expenditures
(amounts in millions)
2001 2002 2003 Total
New generating facilities $ 25.0* $ 0.2 $ 1.1 $ 26.3
Additions to existing
generating facilities 10.0 8.9 13.0 31.9
Transmission facilities 5.8 4.1 3.0 12.9
Distribution system
additions 20.8 22.8 24.0 67.6
General and other additions 1.7 2.3 2.1 6.1
Total $ 63.3 $ 38.3 $ 43.2 $ 144.8
* Includes $4.0 million of
AFUDC
Our projected construction plans include expenditures for the
350 megawatt expansion project at the State Line Power Plant
scheduled for commercial operation in June 2001. Additions to our
transmission and distribution systems to meet projected increases
in customer demand constitute the majority of the remainder of the
projected construction expenditures for the three-year period
listed above.
Estimated construction expenditures are reviewed and adjusted
for, among other things, revised estimates of future capacity
needs, the cost of funds necessary for construction and the
availability and cost of alternative power. Actual construction
expenditures may vary significantly from the estimates due to a
number of factors including changes in equipment delivery
schedules, changes in customer requirements, construction delays,
ability to raise capital, environmental matters, the extent to
which we receive timely and adequate rate increases, the extent of
competition from independent power producers and co-generators,
other changes in business conditions and changes in legislation and
regulation, including those relating to the energy industry. See
"Regulation" below and Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations -
Competition."
Fuel
Coal supplied approximately 82.5% of our total fuel
requirements in 2000 based on kilowatt-hours generated. The
remainder was supplied by natural gas (16.3%) with oil generation
providing 1.2%.
Our 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 86% Western coal (Powder River Basin)
and 14% blend coal on a tonnage basis. Our average coal inventory
target at Asbury is approximately 60 days. As of December 31, 2000,
we had sufficient coal on hand to supply anticipated requirements
at Asbury for 90 days.
Our Riverton Plant fuel requirements are primarily met by coal
with the remainder supplied by natural gas and oil. The Riverton
Plant is currently burning 100% Western coal (Powder River Basin)
on Unit No. 8 and a blend consisting of approximately 75% Western
coal (Powder River Basin) and 25% blend coal on Unit No. 7 on a
tonnage basis. Our average coal inventory target at Riverton is
approximately 60 days. As of December 31, 2000, we had coal
supplies on hand to meet anticipated requirements at the Riverton
Plant for 54 days.
We have a long-term contract, expiring in 2004, with a
subsidiary of Peabody Holding Company, Inc. for the supply of low
sulfur Western coal (Powder River Basin) at the Asbury and Riverton
Plants during the term of the contract. This Peabody coal is
supplied from the Rochelle/North Antelope mines located in Campbell
County, Wyoming, and is shipped to the Asbury Plant by rail, a
distance of approximately 800 miles. The coal is delivered under a
transportation contract with Union Pacific Railroad Company and The
Kansas City Southern Railway Company. We are currently leasing one
125-car aluminum unit train, which delivers Peabody coal to the
Asbury Plant. The Peabody coal is transported from Asbury to
Riverton via truck. Asbury blend coal is currently being supplied
under a short-term contract, expiring December 31, 2001, with
GENWAL Resources, Inc. This coal is supplied from the Crandall
Canyon mine near Huntington, Utah and has been transported by rail
by Union Pacific Railroad Company and The Kansas City Southern
Railway Company. We are currently negotiating a contract with the
Burlington Northern and Santa Fe Railway Company for transportation
of this coal. The Riverton Plant blend coal is supplied under a
contract expiring December 31, 2001, with Phoenix Coal Sales. The
Phoenix coal is transported to Riverton via truck.
Since 1995, our Energy Center and State Line combustion
turbine facilities have been fueled primarily by natural gas with
oil being used as a backup fuel. Based on current and projected
natural gas prices versus oil prices, it is expected that the
Energy Center facility will be operated throughout the first
quarter of 2001 on oil when it is more economical to do so. We
have increased our target oil inventory at the Energy Center
facility from three days of full load operation to five days. We
continue to maintain an oil inventory of approximately three days
of full load operation for State Line Unit No. 1.
We have a firm agreement with Williams Natural Gas Company,
expiring May 31, 2016, for the transportation of natural gas to the
State Line Power Plant, which is jointly owned with Westar
Generating. This transportation can also supply natural gas to the
Energy Center or the Riverton Plant, as elected by us on a
secondary basis. We expect that our remaining gas transportation
requirements, as well as the majority of our natural gas supply
requirements, will be met by short-term forward contracts with up
to five years duration and spot purchases.
Unit No. 1 at the Iatan Plant is a coal-fired generating unit
which is jointly-owned by Kansas City Power & Light (70%),
UtiliCorp (18%) and us (12%). Low sulfur Western coal in quantities
sufficient to meet substantially all of Iatan's requirements is
supplied under a long-term contract expiring on December 31, 2003,
between the joint owners and the Thunder Basin Coal Company. The
coal is transported by rail under a contract expiring on December
31, 2010, with the Burlington Northern and Santa Fe Railway Company
and the Kansas City Southern Railway. 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 our facilities:
2000 1999 1998
Coal - Iatan $ 0.823 $ 0.806 $ 0.857
Coal - Asbury 1.076 1.074 1.100
Coal - Riverton 1.167 1.222 1.214
Natural Gas 3.349 2.549 2.495
Oil 6.117 3.869 4.386
Our weighted cost of fuel burned per kilowatt-hour generated
was 1.846 cents in 2000, 1.561 cents in 1999 and 1.570 cents in
1998.
Employees
At December 31, 2000, we had 603 full-time employees, of whom
340 were members of Local 1474 of The International Brotherhood of
Electrical Workers. On January 17, 2000, we and the IBEW entered
into a new three-year labor agreement effective November 1, 1999.
The agreement provided, among other things, for a 3.25% increase in
wages effective October 25, 1999, a 3.5% increase effective
November 6, 2000 and a minimum increase of 2% effective October 22,
2001.
ELECTRIC OPERATING STATISTICS (1)
2000 1999 1998 1997 1996
Electric Operating Revenues
(000s):
Residential $ 108,572 $ 98,787 $ 100,567 $ 88,636 $ 86,014
Commercial 77,601 73,773 71,810 64,940 61,811
Industrial 42,711 41,030 39,805 37,192 35,213
Public authorities 5,927 5,847 5,559 4,995 4,180
Wholesale on-system 11,738 10,682 10,928 9,730 9,482
Miscellaneous 4,546 3,856 4,006 3,341 3,639
Total system 251,095 233,975 232,675 208,834 200,339
Wholesale off-system 7,842 7,090 6,126 5,473 4,595
Total electric operating 258,937 241,065 238,801 214,307 204,934
revenues
Electricity generated and
purchased (000s of Kwh):
Steam 2,193,847 2,378,130 2,228,103 2,372,914 2,231,062
Hydro 51,132 86,349 70,631 77,578 62,860
Combustion turbine 455,678 520,340 439,517 211,872 162,679
Total generated 2,700,657 2,984,819 2,738,251 2,662,364 2,456,601
Purchased 2,255,076 1,686,782 1,970,348 1,839,833 1,968,898
Total generated and 4,955,733 4,671,601 4,708,599 4,502,197 4,425,499
purchased
Interchange (net) 145 (138) (1,894) 1,018 (1,087)
Total system input 4,955,878 4,671,463 4,706,705 4,503,215 4,424,412
Maximum hourly system 993,000 979,000 916,000 876,000 842,000
demand (Kw)
Owned capacity (end of 878,000 878,000 878,000 878,000 724,000
period) (Kw)
Annual load factor (%) 55.12 52.16 55.72 55.38 56.85
Electric sales (000s of Kwh):
Residential 1,660,928 1,509,176 1,548,630 1,429,787 1,440,512
Commercial 1,333,310 1,260,597 1,246,323 1,171,848 1,154,879
Industrial 1,015,779 988,114 960,783 943,287 923,730
Public authorities 96,403 99,739 98,675 101,122 95,652
Wholesale on-system 309,633 297,614 299,256 273,035 262,330
Total system 4,416,053 4,155,240 4,153,667 3,919,079 3,877,103
Wholesale off-system 161,293 198,234 235,391 253,060 219,814
Total electric sales 4,577,346 4,353,474 4,389,058 4,172,139 4,096,917
Company use (000s of Kwh) 8,714 8,583 8,940 9,688 9,584
Lost and unaccounted for 369,818 309,406 308,707 321,388 317,911
(000s of Kwh)
Total system input 4,955,878 4,671,463 4,706,705 4,503,215 4,424,412
Customers (average number of
monthly bills rendered):
Residential 123,618 121,523 119,265 117,271 115,116
Commercial 22,504 22,206 21,774 21,323 20,758
Industrial 345 350 354 346 346
Public authorities 1,674 1,759 1,739 1,720 1,696
Wholesale on-system 7 7 7 7 7
Total system 148,148 145,845 143,139 140,667 137,923
Wholesale off-system 6 6 6 7 9
Total 148,154 145,851 143,145 140,674 137,932
Average annual sales per 13,436 12,419 12,985 12,192 12,514
residential customer (Kwh)
Average annual revenue per $ 878.29 $ 812.91 $ 843.22 $ 755.82 $ 747.19
residential customer
Average residential revenue 6.54 6.55 6.49 6.20 5.97
per Kwh
Average commercial revenue 5.82 5.85 5.76 5.54 5.35
per Kwh
Average industrial revenue 4.20 4.15 4.14 3.94 3.81
per Kwh
(1) See Item 6 - Selected Financial Data for additional financial
information regarding Empire.
</TABLE
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Executive Officers and Other Officers of Empire
The names of our officers, their ages and years of service
with Empire as of December 31, 2000, positions held and effective
date of such positions are presented below. Each of our executive
officers has held executive officer or management positions within
Empire for at least the last five years.
Age at With the Officer
Name 12/31/00 Positions with the Company Company since since
M.W. McKinney 56 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* 59 Vice President - Energy Supply (1995) 1962 1975
Vice President - Finance (1983)
Director (1989)
R.B. Fancher** 60 Vice President - Finance (1995), Vice 1972 1984
President - Corporate Services (1984)
C.A. Stark 56 Vice President - General Services 1980 1995
(1995), Director of Corporate
Planning (1988)
W.L. Gipson*** 43 Executive Vice President (2001), Vice 1981 1997
President - Commercial Operations
(1997), General Manager (1997),
Director of Commercial Operations
(1995), Economic Development Manager
(1987)
D.W. Gibson**** 54 Vice President - Finance (2001), 1979 1991
Director of Financial Services and
Assistant Secretary (1991)
D.L. Coit***** 50 Controller and Assistant Treasurer 1971 2000
(2000) and Assistant Secretary (2001)
Manager Property Accounting (1983)
J.S. Watson 48 Secretary-Treasurer (1995), 1994 1995
Accounting Staff Specialist (1994)
*V.E. Brill retired from his position as Vice President - Energy
Supply effective February 28, 2001 and from his position as
Director effective April 25, 2001.
**R.B. Fancher retired from his position as Vice President -
Finance effective February 28, 2001.
***W.L. Gipson was elected Executive Vice President February 1, 2001
****D.W. Gibson was elected Vice President - Finance February 1, 2001.
*****D.L. Coit was elected Assistant Secretary February 1, 2001.
Regulation
General. As a public utility, we are subject to the
jurisdiction of the Missouri Public Service Commission, the State
Corporation Commission of the State of Kansas, the Corporation
Commission of Oklahoma and the Arkansas Public Service Commission
with respect to services and facilities, rates and charges,
accounting, valuation of property, depreciation and various other
matters. Each such Commission has jurisdiction over the creation
of liens on property located in its state to secure bonds or other
securities. The Kansas Commission also has jurisdiction over the
issuance of securities. Our transmission and sale at wholesale of
electric energy in interstate commerce and our facilities are also
subject to the jurisdiction of the Federal Energy Regulatory
Commission, referred to as 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."
Our Ozark Beach Hydroelectric Plant is operated under a
license from FERC. See Item 2, "Properties - Electric Facilities."
We are disputing a Headwater Benefits Determination Report we
received from FERC on September 9, 1991. The report calculates an
assessment to us for headwater benefits received at the Ozark Beach
Hydroelectric Plant for the period 1973 through 1990 in the amount
of $705,724, and calculates an annual assessment thereafter of
$42,914 for the years 1991 through 2011. We believe that the
methodology used in making the assessment was incorrect and are
contesting the determination. As of December 31, 2000, FERC had
not responded to the comments filed by us on July 31, 1992. We are
currently accruing an amount monthly equal to what we believe the
correct assessment to be.
During 2000, approximately 91% of our electric operating
revenues were received from retail customers. Approximately 88%,
6%, 3% and 3% of such retail revenues were derived from sales in
Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales
subject to FERC jurisdiction represented approximately 8% of our
electric operating revenues during 2000.
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 our
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
We are subject to various federal, state, and local laws and
regulations with respect to air and water quality as well as other
environmental matters. We believe that our operations are in
compliance with present laws and regulations.
Air. The 1990 Amendments to the Clean Air Act, referred to as
the 1990 Amendments, affect the Asbury, Riverton, State Line and
Iatan Power Plants. The 1990 Amendments require affected plants to
meet certain emission standards, including maximum emission levels
for sulfur dioxide (SO2) and nitrogen oxide (NOx). When a plant
becomes an affected unit for a particular emission, it locks in the
then current emission standards. The Asbury Plant became an
affected unit under the 1990 Amendments for both SO2 and NOx on
January 1, 1995. The Iatan Plant became an affected unit for both
SO2 and NOx on January 1, 2000. The Riverton Plant became an
affected unit for NOx in November 1996 and for SO2 on January 1,
2000. The State Line Plant became an affected unit for SO2 and NOx
on January 1, 2000.
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 ("EPA") withholds annually a percentage of the
emission allowances awarded to each affected unit and sells those
emission allowances through a direct auction. We receive
compensation from the EPA for the sale of these allowances.
Our Asbury, Riverton and Iatan plants currently burn a blend
of low sulfur Wyoming coal and higher sulfur local coal or burn
100% low sulfur Wyoming coal. The State Line Plant is a gas-fired
facility and does not receive SO2 allowances. However, annual
allowance requirements for the State Line Plant, which are not
expected to exceed 20 allowances per year, will be transferred from
our inventoried bank of allowances. We anticipate, based on current
operations, that the combined actual SO2 allowance need for all
affected plant facilities will exceed the number of allowances
awarded to us annually by the EPA. The SO2 allowances needed to
compensate for this deficit will come from our inventoried bank of
allowances. The inventoried bank of allowances should be
sufficient to cover the annual actual emissions deficit for a
minimum of 10 years. We currently have 35,000 banked allowances.
NOx Emissions. 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 April 2000 the Missouri Department of Natural Resources
promulgated a final rule addressing the ozone moderate non-
attainment classification of the St. Louis area. The final
regulation set a maximum NOx emission rate of 0.25 lbs/mmBtu for
Eastern Missouri and a maximum NOx emission rate of 0.35lbs/mmBtu
for Western Missouri. The Iatan, Asbury, State Line and Energy
Center facilities are affected by this regulation. The compliance
date is set for May 1, 2003. The Iatan, State Line and Energy
Center units presently meet this emission limit. The Asbury Plant
does not. The regulation provides for a NOx emission trading
program and for the generation of Early Reduction Credits during
the years 2000, 2001 and 2002. Early Reduction Credits may be used
for compliance during 2003 and 2004. We are evaluating our options
at this time. In order to comply with the emission rate at Asbury,
installation of a selective catalytic reduction system appears to
be the most viable option. However, NOx trading and the purchase
of Early Reduction Credits may permit the delay of the installation
until 2004 or 2005. Also, the compliance date may be delayed to
coincide with the May 31, 2004 compliance date of the EPA's NOx SIP
call which is applicable to Eastern Missouri.
We have construction and operating permits for our State Line
Power Plant and have continuously operated in compliance with those
permits since they went into operation on May 30, 1995 for Unit No.
1 and June 18, 1997 for Unit No. 2. In July 2000, we received a
request for information from the EPA regarding the State Line Power
Plant. The information request indicated that the State Line Power
Plant units should have an Acid Rain Permit under Title IV of the
1990 Amendments to the Clean Air Act. In response, in August 2000,
we applied for the required Acid Rain Permit with the Missouri
Department of Natural Resources. A continuous emission monitoring
system has been installed on Unit No. 1. Unit No. 2 has been off-
line since September 2000 for construction work associated with its
inclusion in the new combined cycle unit. A continuous monitoring
system will be installed and operational before the unit is placed
back in service in mid-2001. Emission data requests have been
submitted for the year 2000 for both units. As a result of this
situation, we may be subject to fines but, at this time, we cannot
predict the final amount of such fines, if any. Finalization of
the situation is expected in 2001.
Water. We operate under the Kansas and Missouri Water
Pollution Plans that were implemented in response to the Federal
Water Pollution Control Act Amendments of 1972. The Asbury, Iatan,
Riverton, Energy Center and State Line facilities are in compliance
with applicable regulations and have received discharge permits and
subsequent renewals as required. The Asbury permit was issued in
2000. The Riverton Plant's National Pollution Discharge
Elimination System ("NPDES") Permit expired in September 2000. We
have received the draft permit from the Kansas Department of Health
and Environment. This permit will be put on public notice in 2001
without any significant changes. We continue to operate under the
existing permit until finalization of the new 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, and is expected to be issued, by July 2001.
Other. Under Title 5 of the 1990 Amendments, we must obtain
site operating permits for each of our plants from the authorities
in the state in which the plant is located. These permits, which
are valid for five years, regulate the plant site's total
emissions; including emissions from stacks, individual pieces of
equipment, road dust, coal dust and steam leaks. We have been
issued permits for Asbury, State Line and the Energy Center Power
Plants. The Riverton Plant has not been issued an operating permit
at this time. The State of Kansas requested that we draft the
Title V Permit and submit it to the state. The permit has been
drafted and submitted. We expect this permit will be issued during
2001.
Conditions Respecting Financing
Our Indenture of Mortgage and Deed of Trust, dated as of
September 1, 1944, as amended and supplemented (the "Mortgage"),
and our Restated Articles of Incorporation (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, 2000, we could have issued under
the Mortgage approximately $122.2 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,
2000, we had retired bonds and net property additions which would
enable the issuance of at least $223.4 million principal amount of
bonds.
Under the Restated Articles, (a) cumulative preferred stock
may be issued only if our net income 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 our capital and surplus. We
redeemed all of our outstanding preferred stock on August 2, 1999
and accordingly, the Articles do not restrict the amount of
unsecured indebtedness that we may have outstanding.
ITEM 2. PROPERTIES
Electric Facilities
At December 31, 2000, we owned generating facilities
(including its interest in Iatan Unit No. 1) with an aggregate
generating capacity of 878 megawatts.
Our principal electric generating plant is the Asbury Plant
with 213 megawatts of generating capacity. The Plant, located near
Asbury, Missouri, is a coal-fired generating station with two steam
turbine generating units. The Plant presently accounts for
approximately 24% of our owned generating capacity and in 2000
accounted for approximately 48% of the energy generated by us.
Routine plant maintenance, during which the entire Plant is taken
out of service, is scheduled once each year, normally for
approximately four weeks in the spring. Every fifth year the spring
outage is scheduled to be extended to a total of six weeks to
permit inspection of the Unit No. 1 turbine. The last such outage
was in 1996 and the next such extended outage is scheduled to occur
between September 15, 2001 and November 25, 2001, a total of ten
weeks. The 2001 five-year major generator turbine inspection is
being extended to allow for the change out of Asbury's five cyclone
burners and the upgrading of the control system to a digital
system. 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, we typically experience increased purchased power and fuel
costs associated with replacement energy. This year's outage is
being moved to the fall when the new State Line Combined Cycle Unit
is expected to be operational to help decrease the need for
purchased power. See Item 1 "Business - Regulation - Fuel
Adjustment Clauses," for additional information concerning
increased purchased power and fuel costs.
Our generating plant located at Riverton, Kansas, has two
steam-electric generating units with an aggregate generating
capacity of 92 megawatts and three gas-fired combustion turbine
units with an aggregate generating capacity of 44 megawatts. The
steam-electric generating units burn coal as a primary fuel and
have the capability of burning natural gas. The last five-year
scheduled maintenance outage for the Riverton Plant occurred during
the second quarter of 1998.
We own a 12% undivided interest in the 670 megawatt coal-fired
Unit No. 1 at the Iatan Generating Station located 35 miles
northwest of Kansas City, Missouri, as well as a 3% interest in the
site and a 12% interest in certain common facilities. We are
entitled to 12% of the unit's available capacity and are obligated
to pay for that percentage of the operating costs of the Unit.
Kansas City Power & Light and UtiliCorp own 70% and 18%,
respectively, of the Unit. Kansas City Power & Light operates the
unit for the joint owners. See Note 10 of "Notes to Financial
Statements" under Item 8.
We also have two combustion turbine peaking units at the
Empire Energy Center in Jasper County, Missouri, with an aggregate
generating capacity of 180 megawatts. These peaking units operate
on natural gas as well as oil.
Our 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, we and Westar
Generating, Inc., 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
"Combined Cycle Unit"). This Combined Cycle Unit will consist of
the combination of an additional combustion turbine, two heat
recovery steam generators and a steam turbine and auxiliary
equipment with an already existing combustion turbine. We will own
an undivided 60% interest in the Combined Cycle Unit with Westar
Generating owning the remainder. We are entitled to 60% of the
capacity of the Combined Cycle Unit. We will contribute our
existing 152-megawatt State Line Unit No. 2 combustion turbine to
the Combined Cycle Unit, and as a result, upon commercial
operation, the Combined Cycle Unit will provide us with
approximately 150 megawatts of additional capacity. The total cost
of this construction expansion project is estimated to be $204
million. Our share of this amount, after the transfer to Westar
Generating 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 $108 million.
Our hydroelectric generating plant, located on the White River
at Ozark Beach, Missouri, has a generating capacity of 16
megawatts, subject to river flow. We have a long-term license from
FERC to operate this plant which forms Lake Taneycomo in
Southwestern Missouri.
At December 31, 2000, our transmission system consisted of
approximately 22 miles of 345 kV lines, 420 miles of 161 kV lines,
754 miles of 69 kV lines and 81 miles of 34.5 kV lines. Its
distribution system consisted of approximately 6,301 miles of line.
Our electric generation stations are located on land owned in
fee. We own a 3% undivided interest as tenant in common with
Kansas City Power & Light and UtiliCorp in the land for the Iatan
Generating Station. We will own a similar interest in 60% of the
land used for the State Line Combined Cycle Unit. Substantially
all of our electric transmission and distribution facilities are
located either (1) on property leased or owned in fee; (2) over
streets, alleys, highways and other public places, under franchises
or other rights; or (3) over private property by virtue of
easements obtained from the record holders of title. Substantially
all of our property, plant and equipment are subject to the
Mortgage.
Water Facilities
We also own and operate water pumping facilities and
distribution systems consisting of a total of approximately 80
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
Our common stock is listed on the New York Stock Exchange. On
March 1, 2001, there were 7,060 record holders of our common stock.
The high and low sale prices for our common stock as reported by
the New York Stock Exchange for composite transactions, and the
amount per share of quarterly dividends declared and paid on the
common stock for each quarter of 2000 and 1999 were as follows:
Price of Common Stock Dividends Paid
2000 1999 Per Share
High Low High Low 2000 1999
First Quarter $ 23.125 $ 18.938 $ 25.625 $ 22.000 $ 0.32 $ 0.32
Second Quarter 24.563 19.688 26.313 20.688 0.32 0.32
Third Quarter 27.063 22.125 26.750 25.375 0.32 0.32
Fourth Quarter 30.750 22.875 25.688 21.688 0.32 0.32
Holders of our common stock are entitled to dividends if, as,
and when declared by the Board of Directors, out of funds legally
available therefore, subject to the prior rights of holders of any
outstanding cumulative preferred stock and preference stock.
The Mortgage and the Restated Articles contain certain
dividend restrictions. The most restrictive of these is contained
in the Mortgage, which provides that we may not declare or pay any
dividends (other than dividends payable in shares of its common
stock) or make any other distribution on, or purchase (other than
with the proceeds of additional common stock financing) any shares
of, our common stock if the cumulative aggregate amount thereof
after August 31, 1944, (exclusive of the first quarterly dividend
of $98,000 paid after said date) would exceed the earned surplus
(as defined) accumulated subsequent to August 31, 1944, or the date
of succession in the event that another corporation succeeds to our
rights and liabilities by a merger or consolidation. As of
December 31, 2000, this dividend restriction did not affect any of
our retained earnings.
Our Dividend Reinvestment and Stock Purchase Plan was
terminated on October 1, 2000 in compliance with terms of the
merger agreement with UtiliCorp United Inc. We will implement a new
Direct Stock Purchase and Dividend Reinvestment Plan effective in
the second quarter 2001. Participants in this plan may acquire, at
a 3% discount, newly issued common shares with reinvested
dividends. Participants may also purchase, at market value, newly
issued common shares with optional cash payments on a weekly basis.
We will also offer participants the option of safekeeping for their
stock certificates.
On April 27, 2000, the Board of Directors approved a new
shareholder rights plan to replace the existing shareholder rights
plan which expired on July 25, 2000. At the Board of Directors
meeting, the Directors declared a dividend distribution of one
right for each share of our Common Stock to holders of record of
our Common Stock at the close of business on July 26, 2000.
The new shareholders rights plan provides each of the common
stockholders one Preference Stock Purchase Right ("Right") for each
share of common stock owned. One Right enables the holder to
acquire one one-hundredth of a share of Series A Participating
Preference Stock (or, under certain circumstances, other
securities) at a price of $75 per one-hundredth of a share, subject
to adjustment. The rights (other than those held by an acquiring
person or group ("Acquiring Person")) will be exercisable only if
an Acquiring Person acquires 10% or more of our common stock or if
certain other events occur. See Note 5 of "Notes to Financial
Statements" under Item 8 for additional information.
Our By-laws provide that K.S.A. Sections 17-1286 through 17-
1298, the Kansas Control Share Acquisitions Act, will not apply to
control share acquisitions of our capital stock.
See Note 4 of "Notes to Financial Statements" under Item 8 for
additional information regarding our common stock.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands, except per share amounts)
2000 1999 1998 1997 1996
Operating revenues $ 260,003 $ 242,162 $ 239,858 $ 215,311 $ 205,984
Operating income $ 45,902 $ 42,576 $ 47,372 $ 40,962 $ 36,652
Total allowance for funds $ 5,775 $ 1,193 $ 409 $ 1,226 $ 1,420
used during construction
Net income $ 23,617 $ 22,170(1)$ 28,323 $ 23,793 $ 22,049
Earnings applicable to 23,617 19,463(1)$ 25,912 $ 21,377 $ 19,633
common stock
Weighted average number of
common shares outstanding 17,503,665 17,237,805 16,932,704 16,599,269 16,015,858
Basic and diluted earnings $ 1.35 $ 1.13(1)$ 1.53 $ 1.29 $ 1.23
per weighted 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 94.9% 114.5% 83.7% 99.4% 104.5%
Allowance for funds used
during construction as a
percentage of earnings
applicable to common stock 24.5% 6.2% 1.6% 5.7% 7.2%
Book value per common share
outstanding at end of year $ 13.62 $ 13.44 $ 13.40 $ 13.03 $ 12.93
Capitalization:
Common equity $ 240,153 $ 234,188 $ 229,791 $ 219,034 $ 213,091
Preferred stock without
mandatory redemption $ 0 $ 0 $ 32,634 $ 32,902 $ 32,902
provisions
Long-term debt $ 325,644 $ 345,850 $ 246,093 $ 196,385 $ 219,533
Ratio of earnings to fixed 2.25 2.70 3.32 3.01 3.11
charges
Ratio of earnings to combined
fixed charges and preferred
stock dividend requirements 2.25 2.40 2.78 2.50 2.53
Total assets $ 829,739 $ 731,409 $ 653,294 $ 626,465 $ 596,980
Utility plant in service
at original cost $ 918,622 $ 870,329 $ 831,496 $ 797,839 $ 717,890
Utility plant expenditures
during the year $ 129,965 $ 69,642 $ 47,366 $ 53,280 $ 59,373
(1) Reflects $5,772,292 of merger costs associated with our proposed
merger with UtiliCorp.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
TERMINATED MERGER WITH UTILICORP
Empire and UtiliCorp United Inc., a Delaware corporation
("UtiliCorp"), entered into an Agreement and Plan of Merger, dated
as of May 10, 1999 (the "Merger Agreement"), which provided for a
merger of our company with and into UtiliCorp, with UtiliCorp being
the surviving corporation. The merger was conditioned, among other
things, upon approvals of various federal and state regulatory
agencies, with either company having the right to terminate the
Merger Agreement if all regulatory approvals were not obtained by
December 31, 2000. All approvals were not received by this date
and UtiliCorp notified us on January 2, 2001 that it was exercising
its right to terminate the Merger Agreement.
On July 26, 2000, the FERC granted conditional approval to the
Merger. On December 4, 2000, the Company received an order from
the Administrative Law Judge ("ALJ") of the Arkansas Public Service
Commission ruling that the proposed regulatory plan not be
approved. In addition, the ALJ stated that he was unable to
separate the application for approval of the merger and the
proposed regulatory plan, and therefore could not conclude that the
merger was consistent with the public interest, the standard for
merger approval in Arkansas. On December 11, 2000, the Arkansas
Public Service Commission issued an order adopting and affirming
the December 4, 2000 order without modification. On December 14,
2000, we and UtiliCorp filed for a rehearing with the Arkansas
Public Service Commission. The Oklahoma Corporation Commission
approved the proposed merger on December 11, 2000 but did not
address the proposed regulatory plan, indicating that such issues
would be addressed if raised in future rate proceedings. The
Missouri Public Service Commission approved the proposed merger on
December 28, 2000 but rejected the proposed regulatory plan. The
Kansas Corporation Commission had not yet ruled on the proposed
merger and regulatory plan when the Merger Agreement was terminated
by UtiliCorp on January 2, 2001.
As a result of the termination of the merger by UtiliCorp,
approximately $6.1 million in merger related expenses that were not
tax deductible when incurred by us, have now become deductible.
This deduction was taken in January 2001, decreasing income tax
expense and increasing operating income for the first quarter of
2001 by approximately $2.3 million.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
results of operations for the year ended December 31, 2000,
compared to the year ended December 31, 1999, and for the year
ended December 31, 1999, compared to the year ended December 31,
1998.
Operating Revenues and Kilowatt-Hour Sales
Of our total electric operating revenues during 2000,
approximately 42% were from residential customers, 30% from
commercial customers, 16% from industrial customers, 5% from
wholesale on-system customers and 3% from wholesale off-system
transactions. The remainder of such revenues were derived from
miscellaneous sources. The percentage changes from the prior year
in kilowatt-hour ("Kwh") sales and revenue by major customer class
were as follows:
Kwh Sales Revenues
2000 1999 2000 1999
Residential 10.1% (2.6)% 9.9% (1.8)%
Commercial 5.8 1.2 5.2 2.7
Industrial 2.8 2.8 4.1 3.1
Wholesale On- 4.0 (0.6) 9.9 (2.3)
System
Total System 6.3 0.1 7.1 0.6
Kwh sales and revenues for our on-system customers increased
during 2000 primarily due to above-average temperatures in August
and September of 2000 as well as unseasonably cold temperatures in
November and December of 2000. Customer growth in 2000 remained at
the same rate as experienced in 1999.
Residential Kwh sales increased 10.1% with revenues increasing
9.9% as compared to 1999 primarily due to the weather conditions
described above. Commercial Kwh sales increased 5.8% with revenues
increasing 5.2% due to these weather conditions as well as
continued increases in business activity throughout our service
territory. Industrial classes also showed an increase in Kwh sales
and revenues due to continued increases in business activity
throughout our service territory.
On-system wholesale Kwh sales increased 4.0% in 2000,
reflecting these weather conditions. Revenues associated with these
sales increased more than the corresponding Kwh sales as a result
of the operation of the fuel adjustment clause applicable to such
FERC regulated sales. This clause permits the pass through to
customers of changes in fuel and purchased power costs.
Kwh sales for our 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 of 1999, 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. 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.
On November 3, 2000, we filed a request with the Missouri
Public Service Commission for a general annual increase in rates
for our Missouri electric customers in the amount of $41,467,926,
or 19.36%. This request is to allow us to recover expenses
resulting from significantly higher natural gas prices than the
levels contemplated by our existing rates as well as our investment
in the Combined Cycle Unit currently under construction at the
State Line Power Plant and other plant additions which have
occurred since our last rate increase in September 1997. The
Missouri Commission has scheduled an evidentiary hearing for May
29, 2001 through June 8, 2001. Any rate increase approved as a
result of the filing would not become effective before late in the
third quarter of 2001. We cannot predict the extent of any
increase which might be granted as a result of this filing.
Because of the timing of the decision with respect to the
November 2000 request and the resulting delay in recovery of
permanent rates as well as the expectation of continuing high
natural gas prices and increased gas usage when the State Line
Combined Cycle Unit begins operation, we filed a request with the
Missouri Public Service Commission on February 16, 2001 for an
interim increase in rates for our Missouri electric customers in
the amount of $16,770,495, or 8.18%. We asked for this increase
to be collected between March 1, 2001 and September 30, 2001, when
we anticipate the permanent case could be concluded. On March 8,
2001 the Missouri Commission dismissed the interim case stating
that Empire had failed to show that it was facing an emergency or
near emergency situation, the standard for interim relief, and
as a result no interim rate increase was granted. We will continue
to actively pursue the permanent rate case described above.
In addition to sales to our own customers, we sell power to
other utilities as available and provide transmission service
through our system for transactions between other energy suppliers.
During 2000 revenues from such off-system transactions were
approximately $10.6 million as compared to approximately $9.6
million in 1999 and approximately $8.3 million during 1998, despite
a decline in Kwh sales for both years. The increase in revenues
during 2000 while Kwh sales were declining was primarily the result
of the ability to sell power at market-based rates. Pursuant to
orders issued by the FERC and subsequent tariffs filed by us and
SPP, these off-system sales have been opened up to competition.
See "- Competition" below for more information on these open-access
tariffs.
Our future revenues from the sale of electricity will continue
to be affected by economic conditions, business activities,
competition, weather, fuel costs, 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 and our ability to receive adequate and timely rate
relief.
Operating Revenue Deductions
During 2000, total operating expenses increased approximately
$19.5 million (15.3%) compared to the prior year. Total purchased
power costs increased by approximately $20.5 million (46.0%) during
2000 reflecting increased demand in the third and fourth quarters
of 2000. Decreased availability of some of our generating units
during the third quarter of 2000 and escalating natural gas prices
(which at times made it more economical to purchase power than to
run our gas-fired units, particularly in September) added to the
increase in purchased power. The Riverton Plant's coal-fired Unit
No. 7 was out of service for its scheduled fall outage from
September 15 to November 9 and Unit No. 8, also coal-fired, was out
of service for its scheduled fall outage from September 29 to
October 16. The State Line Plant's Unit No. 2 was taken out of
service on September 12 to begin its transformation into a combined-
cycle unit and will be out of service until the combined-cycle unit
goes into commercial operation, which is scheduled for June 2001.
Total fuel costs were up approximately $3.6 million (8.1%)
during 2000 as compared to the same period in 1999 primarily
reflecting the increased generation from the gas turbines at the
Energy Center and the State Line Power Plant in the fourth quarter
of 2000. The extremely cold temperatures in December resulted in a
significant increase in the price of purchased power, making it
more economical for us to run our gas-fired turbines. In addition,
escalating natural gas prices made it more economical for the
Energy Center to run its dual-fuel turbines mainly on oil in
December. Natural gas prices were higher by 31.3% during 2000 as
compared to 1999.
Merger related expenses, which were not tax deductible when
they were incurred, were $5.4 million (94.3%) less during 2000 as
compared to 1999.
Other operating expenses increased approximately $0.7 million
(2.3%) during 2000, compared to 1999, mainly due to a $0.5 million
addition to the bad debt reserve in the third quarter. Maintenance
and repairs expense decreased approximately $1.6 million (9.5%)
during 2000 primarily due to decreased maintenance on the
combustion turbines at Energy Center as well as decreased levels of
distribution maintenance.
Depreciation and amortization expense increased approximately
$1.4 million (5.4%) during 2000, compared to 1999, due to increased
levels of plant and equipment placed in service. Total provision
for income taxes decreased approximately $4.5 million (28.3%)
during 2000 due primarily to lower taxable income. See Note 9 of
"Notes to Financial Statements" under Item 8 for additional
information regarding income taxes. Other taxes decreased
approximately $0.3 million (2.6%) during the year.
During 1999, total operating expenses increased approximately
$6.1 million (5.1%) compared to the prior year. Merger related
expenses, which were not tax deductible when they were incurred,
contributed $5.8 million to this increase.
Total purchased power costs decreased by approximately $2.9
million (6.0%) during 1999, primarily due to increased availability
of our 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 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 us to run our 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 our 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 1999. 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.
Nonoperating Items
Total allowance for funds used during construction ("AFUDC")
amounted to approximately 24.5% of earnings applicable to common
stock during 2000, 6.1% during 1999, and 1.6% during 1998. AFUDC
increased significantly during 2000 reflecting higher levels of
construction work in progress related to the State Line Project.
AFUDC increased during 1999 over the same period in 1998, also
reflecting the higher levels of construction work in progress due
mainly to the State Line Project. See Note 1 of "Notes to
Financial Statements" under Item 8. Total AFUDC will decrease
following the completion of the State Line Project scheduled for
June 2001.
Interest charges on long-term debt increased $7.0 million
(35.8%) during 2000 due to the issuance of $100 million of our
unsecured Senior Notes in November 1999. Interest charges on long-
term debt increased $1.5 million (8.6%) during 1999 as compared to
the prior year due to the issuance of $50 million of our First
Mortgage Bonds in April 1998 as well as the Senior Notes in
November 1999. The proceeds from the Senior Notes were used to
repay short-term indebtedness, including approximately $33.1
million in commercial paper incurred in connection with our
preferred stock redemption on August 2, 1999, as well as that
incurred in connection with our construction program. The proceeds
from our First Mortgage Bonds were added to our general funds and
were used to repay $23 million of our First Mortgage Bonds due May
1, 1998 and to repay short-term indebtedness, including that
incurred in connection with our construction program. Commercial
paper interest decreased $0.4 million (25.4%) during the year due
to decreased usage of short-term debt for financing purposes.
Interest income increased $0.1 million (27.5%), reflecting the
higher balances of cash available for investment.
Earnings
Basic and diluted earnings per weighted average share of
common stock were $1.35 during 2000 compared to $1.13 in 1999.
Excluding merger related expenses, earnings per share would have
been $1.37 during 2000 compared to $1.46 in 1999. Earnings per
share, although higher because of favorable weather conditions,
increased AFUDC and decreased merger expenses, were negatively
impacted by significantly increased natural gas prices and
purchased power costs.
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 $1.3 million in
excess consideration paid on redemption of our 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.
We anticipate that assuming normal weather conditions and
continued high natural gas prices, our earnings in 2001 are likely
to decline until we receive adequate and timely rate relief as a
result of the permanent rate increase we are seeking as disclosed
above.
In addition, earnings for the first quarter of 2001 will
reflect the reversal of the non-deductibility of merger related
expenses as discussed above. This will have the effect of
increasing net income for the first quarter by approximately $2.3
million. Earnings for the first quarter of 2001 will also reflect
$1.2 million of expenses related to severance benefits incurred
under our Change in Control severance pay plan.
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 we operate 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. No legislative action has yet been taken and
none is expected during the current 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 was formed to study all issues in Oklahoma and to prepare
legislation to provide a more comprehensive framework for the
transition to retail open access. That legislation was defeated
during the Oklahoma Legislature's 2000 session but will be debated
again in the 2001 session. The target date of July 1, 2002 remains
intact but an extension of this date will also be debated.
The Arkansas Legislature passed a bill in April 1999 that
would deregulate the state's electricity industry as early as
January 2002. 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 us,
that do not seek to recover stranded costs. The Staff of the
Arkansas Public Service Commission filed testimony in October 2000
recommending that the Commission encourage the legislature to
extend the date for retail open access beyond the current statutory
deadline of June 30, 2003. A bill supported by legislative leaders
and the governor was introduced in January 2001. The bill was
enacted in February 2001 and will delay deregulation until October
2003 and give the Commission authority to set further delays in one-
year increments until October 2005. Approximately 2.93% of our
retail electric revenue for 2000 was derived from sales subject to
Arkansas regulation.
In April 1996, the FERC issued Order No. 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. We and the Southwestern
Power Pool ("SPP") have filed open access transmission tariffs
covering these wholesale transmission services. The SPP tariff
applies to most of the transmission services for which our tariff
was designed. Where that is the case, we share 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 our
tariff still applies and we receive 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, or RTO, which we may join as discussed
below.
On December 15, 1999, the FERC issued Order No. 2000 which
encourages the development of RTOs. RTOs are designed to control
the wholesale transmission services of the utilities in 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. The SPP filed with the FERC on
December 30, 1999 for RTO status. This filing was rejected by the
FERC as not meeting certain requirements of its Order 2000. The
SPP filed a second request in the fourth quarter of 2000 addressing
the FERC's concerns and continuing to seek RTO status. The FERC
has not yet ruled on the modified filing. We do not expect the
implementation of Order 2000 to have a significantly different
impact on our results of operations than the implementation of
Order 888 and the operation of the SPP tariff had.
Several factors exist which may enhance our ability to compete
if deregulation occurs. Historically, we have been able to
generate and purchase power relatively inexpensively. Despite the
increased natural gas prices and purchased power costs during 2000,
our retail rates were still approximately 17% less than the
electric industry average. In addition, less than 5% of our
electric operating revenues are derived from sales to on-system
wholesale customers, the type of customer for which the FERC is
already requiring wheeling. Our reliance on purchased power should
also be diminished when the State Line Combined Cycle Unit becomes
operational later this year.
We are continuing our investments in non-regulated businesses
which we commenced in 1996. We now lease capacity on our broadband
fiber optics network and provide electronic monitored security,
decorative lighting and other energy services.
LIQUIDITY AND CAPITAL RESOURCES
Our construction-related expenditures totaled approximately
$133.9 million, $71.9 million, and $51.9 million in 2000, 1999 and
1998, respectively.
A breakdown of our 2000 construction expenditures is as
follows:
Construction Expenditures
(amounts in millions)
2000
New construction - State Line Combined Cycle Unit $ 75.5
Distribution and transmission system additions 37.0
Combustion turbine improvements and upgrades 7.3
Additions and replacements - Asbury and Riverton 7.7
Capitalized software costs 0.6
Fiber optics 1.9
General and other additions 3.9
Total $133.9
Approximately 25% of construction expenditures and other funds
requirements for 2000 were satisfied internally from operations.
The other 75% of such requirements were satisfied from short term
borrowings and the issuance of $100 million aggregate principal
amount of unsecured senior notes in November 1999. The unusually
low percentage of these requirements that was satisfied internally
from operations was due primarily to increased construction
expenditures in 2000.
We estimate that our construction expenditures will total
approximately $63.3 million in 2001, $38.3 million in 2002 and
$43.2 million in 2003. Of these amounts, we anticipate that we will
spend $20.8 million, $22.8 million and $24.0 million in 2001, 2002
and 2003, respectively, for additions to our distribution system to
meet projected increases in customer demand. These construction
expenditure estimates also include approximately $25.0 million,
$0.2 million and $1.1 million in 2001, 2002 and 2003 respectively,
for the Combined Cycle Unit at the State Line Power Plant. The
total cost of this construction expansion project is estimated to
be $204 million. Our 60% share of this amount is approximately
$122 million before considering our contribution of 40% of already
existing property. However, after the transfer to Westar
Generating 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, our net cash requirement is expected to
be approximately $108 million, excluding AFUDC. For more
information on the Combined Cycle Unit see Item 2, "Properties -
Electric Facilities."
Work is continuing and the Combined Cycle Unit is projected to
be placed into commercial operation by the target date of June
2001. We experienced a tightening labor market for required
skilled craftsmen during the third and fourth quarters of 2000
which resulted in increased project labor costs. The project is now
fully staffed with the required skilled craftsmen and work is
continuing. In April, we placed one of our contractors at the
State Line Power Plant in default of its contract and awarded
completion of the work to another. The contractor in default
petitioned for arbitration, claiming that its contract was not
terminated for fault but rather at our convenience and sought
certain damages. We responded with a claim of our own against the
contractor. The dispute was settled to both parties' satisfaction
through mediation in January 2001.
Westar Generating is responsible for 40% of our expenditures
made in connection with the construction and operation of the
Combined Cycle Unit. In addition, Westar Generating had been
making monthly prepayments to us, the last of which was made in
October 2000. These prepayments were for the future transfer to
Westar Generating 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 us. The Missouri and Arkansas Commissions have
approved our application for permission to sell and transfer an
interest in these assets to Westar Generating. The transfer of
these assets is scheduled for March 2001. The prepayments are
reflected in State Line advance payments on the balance sheet. See
Item 8, "Financial Statements and Supplementary Data."
We estimate that internally generated funds will provide at
least 75% of the funds required in 2001, 2002 and 2003 for
estimated construction expenditures. As in the past, we intend to
utilize short-term debt to finance the additional amounts needed
for such construction and repay such borrowings with the proceeds
of sales of public offerings of long-term debt or equity
securities, including the sale of our common stock pursuant to our
Employee Stock Purchase Plan and from internally-generated funds.
Our Board of Directors authorized the termination of our Dividend
Reinvestment and Stock Purchase Plan effective October 1, 2000 as
contemplated by the Merger Agreement. Our Board of Directors voted
at the February 1, 2001 meeting to reestablish a Dividend
Reinvestment and Stock Purchase Plan for later this year. We will
continue to utilize short-term debt as needed to support normal
operations or other temporary requirements and have a $100 million
line of credit. See Note 6 of "Notes to Financial Statements"
regarding our line of credit. We financed our preferred stock
redemption on August 2, 1999 with approximately $33.1 million in
commercial paper. After redeeming all of our preferred stock, we
are no longer restricted by our Articles as to the amount of
unsecured indebtedness that we may have outstanding at any one
time.
On February 8, 2001, we filed an $80 million shelf
registration statement with the SEC for issuance of our unsecured
debt securities and preferred securities of two newly created
trusts. This amount includes $30 million of unsold securities
previously registered. On March 1, 2001, one of these newly
created trusts, Empire District Electric Trust I, issued 2,000,000
8 1/2% Trust Preferred Securities (liquidation amount $25 per
preferred security) in a public underwritten offering. Holders of
the trust preferred securities are entitled to receive
distributions at an annual rate of 8 1/2% of the $25 liquidation
amount. Distributions are payable quarterly and are tax deductible
by us. The sole asset of the trust is $51.6 million aggregate
principal amount of 8 1/2% Junior Subordinated Debentures due March
1, 2031 issued by us. The terms and interest payments on these
debentures correspond to the terms and distributions on the trust
preferred securities. We have entered into a limited guarantee of
payment of distributions, redemption payments and payments in
liquidation with respect to the trust preferred securities. This
guarantee, when considered together with our obligations under the
related debentures and indenture and the trust agreement governing
the trust, provide a full and unconditional guarantee by us of
amounts due on the outstanding trust preferred securities. The net
proceeds of this offering were added to our general funds and were
used to repay short-term indebtedness.
We also have an effective shelf registration statement on file
with the SEC under which up to an aggregate of $50 million of our
common stock, first mortgage bonds and unsecured debt securities
remain available for issuance. On November 19, 1999, we issued $100
million aggregate principal amount of our unsecured Senior Notes,
the net proceeds of which were added to our general funds and were
used to repay short-term indebtedness, including indebtedness
incurred in connection with our preferred stock redemption and in
connection with our construction program.
On April 28, 1998, we sold to the public in an underwritten
offering $50 million aggregate principal amount of our First
Mortgage Bonds, 6 1/2% Series due 2010. The net proceeds from this
sale were added to our general funds and were used to repay $23
million of our First Mortgage Bonds, 5.70% Series due May 1, 1998
and to repay short-term indebtedness, including indebtedness
incurred in connection with our construction program.
Following announcement of the merger with UtiliCorp, the
ratings for our first mortgage bonds (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 and Standard &
Poor's. Standard & Poor's removed the credit watch but kept the
downward implication in January 2001 after the merger was
terminated. As of December 31, 2000, the ratings for our
securities were as follows:
Moody's Standard &
Poor's
First Mortgage Bonds A2 A-
First Mortgage Bonds - Aaa AAA
Pollution Control Series
Senior Notes A3 Not Rated
Commercial Paper P-1 A-2
Trust Preferred Securities baa1 BBB
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Interest Rate Risk. We are exposed to changes in interest
rates as a result of significant financing through our issuance of
commercial paper. We manage our interest rate exposure by limiting
our variable-rate exposure to a certain percentage of total
capitalization, as set by policy, and by monitoring the effects of
market changes in interest rates. See Notes 6 and 7 of "Notes to
Financial Statements" under Item 8 for further information.
If market interest rates average 1% more in 2001 than in 2000,
our interest expense would increase, and income before taxes would
decrease by approximately $700,000. This amount has been determined
by considering the impact of the hypothetical interest rates on our
commercial paper balances as of December 31, 2000. These analyses
do not consider the effects of the reduced level of overall
economic activity that could exist in such an environment. In the
event of a significant change in interest rates, management would
likely take actions to further mitigate its exposure to the change.
However, due to the uncertainty of the specific actions that would
be taken and their possible effects, the sensitivity analysis
assumes no changes in our financial structure.
Commodity Price Risk. We are exposed to the impact of market
fluctuations in the price and transportation costs of coal, natural
gas, and electricity and employ established policies and procedures
to manage the risks associated with these market fluctuations. At
this time none of our commodity purchase or sale contracts meet the
definition of financial instruments.
ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY 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, 2000 and 1999, and the results
of its operations and its cash flows for each of the three years
in the period ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States of
America. 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 of America, which require that we plan and perform
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
St. Louis, Missouri
January 31, 2001
Balance Sheet
December 31,
2000 1999
Assets
Utility plant, at original cost:
Electric $ 921,033,228 $ 871,263,673
Water 7,528,233 7,023,246
Construction work in progress 120,126,571 41,712,243
1,048,688,032 919,999,162
Accumulated depreciation 328,370,253 303,951,518
720,317,779 616,047,644
Current assets:
Cash and cash equivalents 2,490,580 20,778,856
Accounts receivable - trade, net 19,960,839 17,377,963
Accrued unbilled revenues 11,824,546 6,660,318
Accounts receivable - other 3,631,654 6,726,734
Fuel, materials and supplies 14,589,253 15,978,790
Prepaid expenses 3,034,716 1,129,021
55,531,588 68,651,682
Noncurrent assets and deferred charges:
Regulatory assets 36,590,292 37,075,852
Unamortized debt issuance costs 3,769,628 4,175,240
Other 13,530,017 5,458,466
53,889,937 46,709,558
Total Assets $ 829,739,304 $ 731,408,884
Capitalization and Liabilities
Common stock, $1 par value, 20,000,000 shares
authorized, 17,596,530 and 17,369,855 shares
issued and outstanding, respectively $ 17,596,530 $ 17,369,855
Capital in excess of par value 168,439,089 163,909,731
Retained earnings 54,117,292 52,908,432
Total common stockholders' equity 240,152,911 234,188,018
Long-term debt 325,643,766 345,850,169
565,796,677 580,038,187
Current liabilities:
Current maturities of long-term debt 20,000,000 -
(Note 6)
Accounts payable and accrued liabilities 35,782,456 25,232,221
Commercial paper 69,500,000 -
Customer deposits 3,789,583 3,686,691
Taxes accrued 1,823,513 -
Interest accrued 5,402,131 5,026,356
136,297,683 33,945,268
Commitments and Contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liability 14,170,175 15,295,992
Deferred income taxes 83,581,349 78,913,545
Unamortized investment tax credits 7,231,000 7,811,000
Postretirement benefits other than pensions 4,835,897 4,592,721
State Line advance payments 14,399,757 7,895,241
Other 3,426,766 2,916,930
127,644,944 117,425,429
Total Capitalization and Liabilities $ 829,739,304 $ 731,408,884
The accompanying notes are an integral part of these financial statements.
Statement of Income
Year ended December 31,
2000 1999 1998
Operating revenues:
Electric $ 258,937,329 $ 241,065,202 $ 238,800,831
Water 1,066,129 1,096,338 1,057,460
260,003,458 242,161,540 239,858,291
Operating revenue deductions:
Operating expenses:
Fuel 48,899,577 45,251,427 41,876,064
Purchased power 65,238,096 44,696,792 47,572,541
Merger related expenses 327,397 5,772,292 -
Other 32,570,495 31,833,132 31,972,081
147,035,565 127,553,643 121,420,686
Maintenance and repairs 14,795,210 16,345,268 17,522,871
Depreciation and amortization 27,783,573 26,366,695 24,980,637
Provision for income taxes 11,375,000 15,862,429 16,190,000
Other taxes 13,112,095 13,457,782 12,372,321
214,101,443 199,585,817 192,486,515
Operating income 45,902,015 42,575,723 47,371,776
Other income and deductions:
Allowance for equity funds used
during construction 2,373,710 56,845 8,938
Interest income 641,602 503,355 263,801
Other - net (660,285) (662,118) (840,557)
2,355,027 (101,918) (567,818)
Income before interest $ 48,257,042 $ 42,473,805 $ 46,803,958
charges
Interest charges:
Long-term debt 26,355,901 19,402,734 17,873,833
Allowance for borrowed funds
used during construction (3,401,325) (1,135,776) (400,044)
Other 1,685,312 2,036,708 1,006,831
24,639,888 20,303,666 18,480,620
Net income 23,617,154 22,170,139 28,323,338
Preferred stock dividend requirements - 1,403,025 2,411,784
Excess consideration on redemption of
preferred stock - 1,304,504 -
Net income applicable to $ 23,617,154 $ 19,462,610 $ 25,911,554
common stock
Weighted average number of
common shares outstanding 17,503,665 17,237,805 16,932,704
Basic and diluted earnings per weighted
average share of common stock $ 1.35 $ 1.13 $ 1.53
Dividends per share of
common stock $ 1.28 $ 1.28 $ 1.28
The accompanying notes are an integral part of these financial statements.
Statement of Common Stockhloder's Equity
Year ended December 31,
2000 1999 1998
Common stock, $1 par value:
Balance, beginning of year $ 17,369,855 $ 17,108,799 $ 16,776,654
Stock/stock units issued through:
Dividend reinvestment and stock
purchase plan 185,622 223,910 259,267
Employee benefit plans 41,053 37,146 72,878
Balance, end of year $ 17,596,530 $ 17,369,855 $ 17,108,799
Capital in excess of par value:
Balance, beginning of year $ 163,909,731 $ 156,975,596 $ 150,784,239
Excess of net proceeds over
par value of stock issued:
Stock plans 4,529,358 6,934,135 6,191,357
Balance, end of year $ 168,439,089 $ 163,909,731 $ 156,975,596
Retained earnings:
Balance, beginning of year $ 52,908,432 $ 55,706,779 $ 51,472,897
Net income 23,617,154 22,170,139 28,323,338
76,525,586 77,876,918 79,796,235
Less dividends declared:
8 1/8% preferred stock - 1,349,474 2,027,390
5% preferred stock - 124,642 195,090
4 3/4% preferred stock - 126,094 190,000
Common stock 22,408,294 22,063,772 21,676,976
22,408,294 23,663,982 24,089,456
Less: excess consideration on
redemption of preferred stock - 1,304,504 -
Balance, end of year $ 54,117,292 $ 52,908,432 $ 55,706,779
The accompanying notes are an integral part of these financial statements.
Statement of Cash Flows
Year ended December 31,
2000 1999 1998
Operating activities
Net income $ 23,617,154 $ 22,170,139 $ 28,323,338
Adjustments to reconcile net
income to cash flows:
Depreciation and amortization 31,240,530 29,672,416 28,323,595
Pension income (7,780,497) (4,325,229) (2,239,850)
Deferred income taxes, net 2,053,000 4,480,000 3,390,000
Investment tax credit, net (580,000) (580,000) (580,000)
Allowance for equity funds used
during construction (2,373,710) (56,845) (8,938)
Issuance of common stock for
401(k) plan 760,405 753,203 702,801
Issuance of common stock units for
director retirement plan 84,000 84,000 711,000
Other - - 66,955
Cash flows impacted by changes in:
Accounts receivable and accrued
unbilled revenues (4,652,024) (9,309,949) (584,001)
Fuel, materials and supplies 1,389,537 (274,112) (2,489,610)
Prepaid expenses and deferred charges
1,427,249) (3,050,794) 2,431,806
Accounts payable and accrued
liabilities 10,550,235 8,135,949 2,233,691
Customer deposits, interest
and taxes accrued 2,302,180 971,596 84,941
Other liabilities and other
deferred credits 753,012 434,255 (1,883,100)
Net cash provided by
operating activities 55,936,573 49,104,629 58,482,628
Investing activities
Construction expenditures (133,933,927) (71,935,978) (51,917,153)
Allowance for equity funds used
during construction 2,373,710 56,845 8,938
Net cash used in
investing activities (131,560,217) (71,879,133) (51,908,215)
Financing activities
Proceeds from issuance of
first mortgage bonds $ - $ - $ 49,672,000
Proceeds from issuance of
senior notes - 99,818,000 -
Proceeds from issuance of
common stock 3,911,628 6,357,989 5,109,701
Redemption of preferred stock - (32,634,263) -
Reacquired preferred stock - - (267,537)
Excess consideration on
redemption of preferred stock - (1,304,504) -
Dividends (22,408,294) (23,663,982) (24,089,456)
Repayment of first mortgage bonds (286,000) (110,000) (23,000,000)
Net proceeds (repayments) from
short-term borrowings 69,500,000 (14,500,000) (13,500,000)
Payment of debt issue costs 113,518 (797,837) (551,687)
State line advance payments 6,504,516 7,895,241 -
Net cash provided by/(used in)
financing activities 57,335,368 41,060,644 (6,626,979)
Net (decrease) increase in cash
and cash equivalents (18,288,276) 18,286,140 (52,566)
Cash and cash equivalents,
beginning of year 20,778,856 2,492,716 2,545,282
Cash and cash equivalents,
end of year $ 2,490,580 $ 20,778,856 $ 2,492,716
Cash and cash equivalents include cash on hand and temporary
investments purchased with an initial maturity of three months or
less. Interest paid was $26,485,000, $19,301,000, $17,439,000, for
the years ended December 31, 2000, 1999 and 1998, respectively.
Income taxes paid were $8,801,000, $12,221,000 and $14,088,000 for
the years ended December 31, 2000, 1999 and 1998, respectively.
The accompanying notes are an integral part of these financial statements.
1. Summary of Accounting Policies
The Company is subject to regulation by the Missouri Public
Service Commission (MoPSC), the State Corporation Commission
of the State of Kansas (KCC), the Corporation Commission of
Oklahoma (OCC), the Arkansas Public Service 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 2000 were derived as follows:
residential 42%, commercial 30%, industrial 16%, wholesale
8% and other 4%. Following is a description of the
Company's significant accounting policies:
Property and Plant
The costs of additions to property and plant and
replacements for retired property units are capitalized.
Costs include labor, material and an allocation of general
and administrative costs plus an allowance for funds used
during construction. Maintenance expenditures and the
renewal of items not considered units of property are
charged to income as incurred. The cost of units retired is
charged to accumulated depreciation, which is credited with
salvage and charged with removal costs.
Depreciation
Provisions for depreciation are computed at straight-line
rates as approved by regulatory authorities. Such
provisions approximated 3.2%, 3.2% and 3.2% of depreciable
property for 2000, 1999 and 1998, respectively.
Depreciation expense for the years ended December 31, 2000,
1999 and 1998 was $29,664,000, $28,135,000 and $26,655,000,
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 2000, 1999 and 1998 periods was
17,503,665, 17,237,805 and 16,932,704, respectively.
Dilutive stock options for the 2000, 1999 and 1998 periods
were 7,105, 5,290 and 7,775, 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 8.4% for 2000, 5.4% for
1999 and 5.9% for 1998 (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 estimated, but unbilled, revenue and
also a liability for the related taxes.
Accumulated Provision for Uncollectible Accounts
The accumulated provision for uncollectible accounts was
$964,000 at December 31, 2000 and $372,000 at December 31,
1999.
Franchise Taxes
Franchise taxes are collected for and remitted to their
respective cities. Operating revenues include franchise
taxes of $4,560,000, $4,400,000, and $4,400,000 for each of
the years ended December 31, 2000, 1999 and 1998,
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"), entered into an Agreement and
Plan of Merger, dated as of May 10, 1999 (the "Merger
Agreement"), which provided for a merger of the Company with
and into UtiliCorp, with UtiliCorp being the surviving
corporation (the "Merger").
The Merger was unanimously approved by the Boards of
Directors of the constituent companies. The Merger
Agreement required the Company to redeem all of its
outstanding preferred stock according to its terms prior to
the closing.
On August 2, 1999, the Company redeemed all of its
outstanding preferred stock for approximately $34,200,000.
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.
Under the terms of the Merger Agreement, either company
could terminate the Merger Agreement without penalty if all
regulatory approvals were not obtained prior to December 31,
2000. On January 2, 2001, UtiliCorp exercised its right to
terminate the Merger Agreement based on the aforementioned
clause. Upon termination of the merger, approximately $6.1
million of merger related costs that had not been deductible
for income tax purposes became deductible. As a result, the
Company will recognize a tax benefit of approximately $2.3
million in the first quarter of 2001.
The stockholder approval of the merger effected a change in
control under the Company's Change in Control Severance Pay
Plan (the "Plan"). Certain key employees became eligible to
receive compensation as specified under the terms of the
Plan. The termination of the Merger did not relieve the
Company of its obligation under the Plan. As of December
31, 2000, the Company had incurred approximately $194,000 of
obligations to individuals electing voluntary termination
under the Plan. Subsequent to that date, the Company
incurred approximately $1,154,000 in additional obligations
under the Plan.
3. Regulatory Matters
During the three years ending December 31, 2000, the
following rate changes were requested or in effect:
Arkansas
On February 19, 1998, the Company filed a request with the
APSC 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 November 3, 2000, the Company filed a request with the
MoPSC to increase rates in Missouri by approximately
$41,500,000 annually. The request is currently under review
by the MoPSC.
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 certain regulatory assets which are
expected to result in future revenues as these costs are
recovered through the ratemaking process. Historically, all
costs of this nature which are determined by 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:
December 31,
2000 1999
Regulatory Assets
Income taxes $ 25,724,995 $ 24,236,008
Unamortized loss on reacquired debt 8,270,284 8,811,488
Coal contract restructuring costs 1,383,848 1,882,941
Gas supply realignment costs 559,370 829,773
Asbury five year maintenance 263,105 894,567
Other postretirement benefits 388,690 421,075
Total Regulatory Assets $ 36,590,292 $ 37,075,852
Regulatory Liability
Income taxes $ 14,170,175 $ 15,295,992
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. No legislative action has yet
been taken and none is expected during 2001. 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. 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. 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. The Staff of the Arkansas
Public Service Commission filed testimony in October 2000
recommending that the Commission encourage the legislature
to extend the date for retail open access beyond the current
legal deadline of June 30, 2003. A bill supported by
legislative leaders and the governor was introduced in
January 2001. The bill was enacted in February 2001 and
will delay deregulation until October 2003 and give the
Commission authority to set further delays in one-year
increments until October 2005. Approximately 2.93% of the
Company's retail electric revenue for 2000 was derived from
sales subject to Arkansas regulation.
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 2000, 3,759 units were granted under the
Director Retirement Plan for services provided in 2000 and
2,469 units were granted pursuant to the reinvestment plan
described below.
The Company's Dividend Reinvestment and Stock Purchase Plan
(the Reinvestment Plan), which was terminated effective
October 1, 2000, allowed 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 were also allowed to purchase,
for cash and within specified limits, additional stock at
100% of the market price average. Participants in the
Reinvestment Plan did not pay commissions or service charges
in connection with purchases under the Reinvestment Plan.
The Company is in the process of instituting a similar plan
during fiscal 2001.
The Company's Employee Stock Purchase Plan, which terminates
on May 31, 2003, permits the grant to eligible employees of
options to purchase common stock at 90% of the lower of
market value at date of grant or at date of exercise.
Contingent employee stock purchase subscriptions outstanding
and the maximum prices per share were 40,880 shares at
$21.83, 63,985 shares at $23.35, 50,368 shares at $18.34 on
December 31, 2000, 1999 and 1998, respectively. Shares were
issued at $21.26 per share in 2000, $18.34 per share in
1999, and $15.53 per share in 1998.
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 2000, February 1999 and January 1998, grants
for 2,160, 1,144, and 1,535 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 2000, 1999 and 1998, 3,368, 3,300 and
2,641 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 2000, 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 33,926, 30,404
and 33,274 shares of common stock in 2000, 1999 and 1998,
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, 2000, 1,073,616 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.
There was no preferred stock issued and outstanding at
December 31, 2000 or 1999.
On August 2, 1999 the Company redeemed all outstanding 5%,
4_%, and 81/8% 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_% cumulative - $10.20
(aggregate amount $4,080,000); and 81/8 cumulative - $10
(aggregate amount $24,809,980).
On February 8, 2001, the Company filed a registration
statement with the Securities and Exchange Commission
allowing the Company to sell $80,000,000 of preferred
securities, including $30,000,000 of unsold securities
previously registered under a separate registration
statement.
Preference Stock Purchase Rights
On April 27, 2000, the Board of Directors approved a new
shareholder rights plan to replace the existing shareholder
rights plan which expired on July 25, 2000. The new
shareholder rights plan provides each of the common
stockholders one Preference Stock Purchase Right ("Right")
for each share of common stock owned as compared to one-half
of one right per common share under the prior shareholder
rights plan. Each Right enables the holder to acquire one
one-hundredth of a share of Series A Participating
Preference Stock (or, under certain circumstances, other
securities) at a price of $75 per one one-hundredth share,
subject to adjustment. The Rights (other than those held by
an acquiring person or group (Acquiring Person)), which
expire July 25, 2010, will be exercisable only if an
Acquiring Person acquires 10% or more of the Company's
common stock or if certain other events occur. 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. The Company
had 17,544,600 and 8,663,648 Preference Stock Purchase
Rights (Rights) outstanding at December 31, 2000 and 1999,
respectively.
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-one basis.
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, 2000 and 1999 the long-term debt outstanding
was as follows:
2000 1999
First mortgage bonds:
7 1/2% 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
6 1/2% Series due 2010 50,000,000 50,000,000
7.20% Series due 2016 25,000,000 25,000,000
9 3/4% Series due 2020 2,250,000 2,250,000
7% Series due 2023 45,000,000 45,000,000
7 3/4% Series due 2025 30,000,000 30,000,000
7 1/4% Series due 2028 13,330,000 13,616,000
5.3% Pollution Control Series
due 2013 8,000,000 8,000,000
5.2% Pollution Control Series
due 2013 5,200,000 5,200,000
246,280,000 246,566,000
Senior Notes, 7.70% Series
due 2004 100,000,000 100,000,000
Less unamortized net discount (636,234) (715,831)
Less current maturities of
long-term debt (20,000,000) -
$ 325,643,766 $ 345,850,169
(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. Holders must
apply for this redemption during the period
September 1, 2001 to October 1, 2001.
The carrying amount of the Company's long-term debt was
$345,643,766 and $345,850,169 at December 31, 2000 and 1999,
respectively, and its fair market value was estimated to be
approximately $333,748,477 and $329,118,000, 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, 2000, the Company had a $50,000,000
unsecured line of credit. Borrowings are at the higher of
the bank's prime commercial rate or 50 basis points above
the Federal overnight Fed Funds rate and are due 370 days
from the date of each loan, not to exceed June 27, 2001, the
final credit expiration date. The Company also had a
$25,000,000 unsecured line of credit at December 31, 2000,
bearing interest based on the bank's prime commercial rate.
This unsecured line of credit expires on July 31, 2001.
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, 2000 or 1999.
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 $17,846,995 and $30,796,000 daily during 2000 and
1999, respectively, with the highest month-end balances
being $69,500,000 and $65,000,000, respectively. The
weighted daily average interest rates during 2000, 1999 and
1998 were 7.0%, 5.4% and 5.9%, respectively. The weighted
average interest rates of borrowings outstanding at
December 31, 2000 and 1999 were, 7.77% and 6.12%,
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."
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:
2000 1999 1998
Benefit obligation at
beginning of year $ 72,288,124 $ 77,285,598 $ 78,360,097
Service cost 2,182,798 2,516,067 2,400,303
Interest cost 5,579,276 5,368,097 5,046,012
Amendments - 1,744,656 -
Actuarial (gain)/loss (250,025) (10,076,097) (4,065,095)
Benefits paid (4,582,209) (4,550,197) (4,455,719)
Benefit obligation
at end of year $ 75,217,964 $ 72,288,124 $ 77,285,598
2000 1999 1998
Fair value of plan assets at
beginning of year $ 104,485,842 $ 93,153,901 $ 82,106,242
Actual return on plan assets (1,005,567) 15,882,138 15,503,378
Benefits paid (4,582,209) (4,550,197) (4,455,719)
Fair value of plan assets at
end of year $ 98,898,066 $ 104,485,842 $ 93,153,901
Funded status $ 23,680,102 $ 32,197,718 $ 15,868,303
Unrecognized net assets at
January 1, 1986 being amortized
over 17 years (982,313) (1,473,468) (1,964,623)
Unrecognized prior service cost 4,266,641 4,786,072 3,560,847
Unrecognized net gain (15,357,002) (31,683,391) (18,028,407)
Prepaid/(accrued) pension
cost $ 11,607,428 $ 3,826,931 $ (563,880)
Assumptions used in calculating the projected benefit
obligation for 2000 and 1999 include the following:
2000 1999 1998
Weighted average discount rate 7.75% 8.00% 7.00%
Rate of increase in compensation levels 5.00% 5.50% 5.50%
Expected long-term rate of return
on plan assets 9.00% 9.00% 9.00%
Net pension benefit for 2000, 1999 and 1998 is comprised of
the following components:
2000 1999 1998
Service cost - benefits earned
during the period $ 2,182,798 $ 2,516,067 $ 2,400,303
Interest cost on projected
benefit obligation 5,579,276 5,368,097 5,046,012
Expected return on plan assets (9,181,211) (8,323,982) (7,173,641)
Net amortization and deferral (6,361,360) (3,950,993) (2,512,524)
Net pension benefit $ (7,780,497) $ (4,390,811) $ (2,239,850)
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 $16,100,000 at
December 31, 2000, $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 2000, 1999 and 1998
included the following components:
2000 1999 1998
Service cost on benefits earned
during the year $ 931,469 $ 781,017 $ 558,983
Interest cost on projected
benefit obligation 3,142,872 2,281,028 1,593,181
Return on assets (1,007,118) (618,353) (375,581)
Amortization of unrecognized
transition obligation 1,084,017 1,084,017 1,084,017
Unrecognized net (gain)/loss 1,990,806 1,207,628 (720,744)
Net periodic postretirement
benefit cost $ 6,142,045 $ 4,735,337 $ 2,139,856
The estimated funded status of the Company's obligations
under SFAS 106 at December 31, 2000, 1999 and 1998 using a
weighted average discount rate of 7.75%, 8.0% and 7.0%,
respectively, is as follows:
2000 1999 1998
Benefit obligation
at beginning of year $ 28,669,028 $ 24,580,797 $ 23,978,240
Service cost 931,469 781,017 558,983
Interest cost 3,142,872 2,281,028 1,593,181
Actuarial (gain)/loss 5,908,539 2,227,896 (353,055)
Benefits paid (1,400,654) (1,201,710) (1,196,552)
Benefit obligation
at end of year $ 37,251,254 $ 28,669,028 $ 24,580,797
Fair value of plan assets
at beginning of year $ 10,552,442 $ 6,803,302 $ 5,691,142
Employer contributions 5,735,695 4,604,982 2,102,087
Actual return on plan assets 1,168,343 345,870 206,625
Benefits paid (1,400,654) (1,201,710) (1,196,552)
Fair value of plan assets
at end of year $ 16,055,828 $ 10,552,444 $ 6,803,302
Funded Status $(21,195,426) $(18,116,584) $(17,777,495)
Unrecognized transition
obligation 13,008,191 14,092,208 15,176,225
Unrecognized net gain 3,262,230 (494,279) (1,787,030)
Accrued postretirement
benefit cost $ (4,925,005) $(4,518,655) $ (4,388,300)
The assumed 2001 cost trend rate used to measure the
expected cost of healthcare benefits is 9%. The trend rate
decreases through 2003 to an ultimate rate of 6% for 2004
and subsequent years. The effect of a 1% increase in each
future year's assumed healthcare cost trend rate would
increase the current service and interest cost from
$4,100,000 to $5,000,000 and the accumulated postretirement
benefit obligation from $37,300,000 to $44,400,000.
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:
2000 1999 1998
Computed "expected"
federal provision $ 12,290,000 $ 13,360,000 $ 15,480,000
State taxes, net of
federal effect 1,090,000 1,180,000 1,370,000
Adjustment to taxes
resulting from:
Nondeductible merger costs 120,000 2,200,000 -
Investment tax credit
amortization (580,000) (580,000) (580,000)
Other (1,420,000) (160,000) (370,000)
Actual provision $ 11,500,000 $ 16,000,000 $ 15,900,000
Income tax expense components for the years shown are as
follows:
2000 1999 1998
Taxes currently payable
Included in operating
revenue deductions:
Federal $ 8,852,000 $ 10,761,000 $ 12,110,000
State 1,203,000 1,329,000 1,430,000
Included in "other - net" (28,000) 10,000 (450,000)
10,027,000 12,100,000 13,090,000
Deferred taxes
Depreciation and
amortization differences 2,136,000 2,991,800 3,077,000
Loss on reacquired debt (206,000) (206,000) (213,000)
Postretirement benefits 1,408,000 928,000 528,000
Other (1,158,000) (118,371) (454,000)
Asbury five-year maintenance (241,000) (241,000) (241,000)
Software development costs (39,000) 998,000 533,000
Included in "other-net" 153,000 127,571 160,000
Deferred investment tax
credits, net (580,000) (580,000) (580,000)
Total income tax expense $ 11,500,000 $ 16,000,000 $ 15,900,000
Under SFAS 109, temporary differences gave rise to deferred
tax assets and deferred tax liabilities at year end 2000 and
1999 as follows:
Balances as of December 31,
2000 1999
Deferred Tax Deferred Tax Deferred Tax Deferred Tax
Assets Liabilities Assets Liabilities
Noncurrent
Depreciation and other
property related $ 10,661,065 $ 94,692,058 $ 10,630,457 $ 91,009,149
Unamortized investment
tax credits 4,545,873 - 4,910,498 -
Miscellaneous book/tax
recognition differences 2,548,908 6,645,137 3,561,786 7,007,137
Total deferred taxes $ 17,755,846 $101,337,195 $ 19,102,741 $ 98,016,286
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,
2000 and 1999, the Company's property, plant and equipment
accounts include the cost of its ownership interest in the
unit of $45,455,000 and $44,656,000, respectively, and
accumulated depreciation of $30,089,000 and $28,689,000,
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 $204,000,000. 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 $122,400,000. 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 is a party to various claims and legal
proceedings arising out of the normal course of its
business. In the opinion of management, the ultimate
outcome of these claims and lawsuits will not have a
material adverse affect upon the financial condition or
results of operations of the Company.
The Company's 2001 construction budget, including AFUDC, is
$63,334,000. The Company's three-year construction program
for 2001 through 2003, including AFUDC, is estimated to be
approximately $144,778,000.
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 $52,000,000, $50,000,000 and
$64,000,000 in 2000, 1999 and 1998, 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 $35,000,000 in 2001, $29,000,000 in 2002,
$28,000,000 in 2003 and 27,000,000 in 2004 and reducing to
lesser amounts thereafter through 2012.
12. Selected Quarterly Information (Unaudited)
A summary of operations for the quarterly periods of 2000
and 1999 is as follows:
Quarters
First Second Third Fourth
(dollars in thousands except per share amounts)
2000:
Operating revenues $ 54,030 $ 57,428 $ 86,223 $ 62,322
Operating income 8,033 9,314 19,672 8,853
Net income 2,371 3,583 14,332 3,330
Net income applicable 2,371 3,583 14,332 3,330
to common stock
Basic and diluted earnings
per average share of $ .14 $ .21 $ .82 $ .19
common stock
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
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.
13. Recently Issued Accounting Standards
On June 15, 1998, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging
Activities (FAS 133). FAS 133 is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999
(January 1, 2000 for the Company). FAS 133 requires that all
derivative instruments be recorded on the balance sheet at
their fair value. Changes in the fair value of derivatives
are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is
designated as part of a hedge transaction and, if it is, the
type of hedge transaction. Management of the Company
anticipates that, due to its limited use of derivative
instruments, the adoption of FAS 133 will not have a
significant effect on the Company's results of operations or
its financial position.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item with respect to directors
and directorships and with respect to Section 16(a) Beneficial
Ownership Reporting Compliance may be found in our proxy statement for
our Annual Meeting of Stockholders to be held April 25, 2001, which is
incorporated herein by reference.
Pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, the information required by this Item with respect to
executive officers is set forth in Item 1 of Part I of this Form 10-K
under "Executive Officers and Other Officers of Empire."
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation may be found in our
proxy statement for our Annual Meeting of Stockholders to be held
April 25, 2001, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Information regarding the number of shares of our equity
securities beneficially owned by our directors and certain executive
officers and by the directors and executive officers as a group may be
found in our proxy statement for our Annual Meeting of Stockholders to
be held April 25, 2001, which is incorporated herein by reference.
To our knowledge, no person is the beneficial owner of 5% or more
of any class of our voting securities, and there are no arrangements
the operation of which may at a subsequent date result in a change in
control of Empire.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item with respect to certain
relationships and related transactions may be found in our proxy
statement for our Annual Meeting of Stockholders to be held April 25,
2001, 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, 2000 and 1999 24
Statements of income for each of the three years in the period 25
ended December 31, 2000
Statements of common stockholders' equity for each of the three
years in the period ended December 31, 2000 26
Statements of cash flows for each of the three years in the 27
period ended December 31, 2000
Notes to financial statements 28
Schedule for the years ended December 31, 2000, 1999 and 1998:
Schedule II - Valuation and qualifying accounts 47
All other schedules are omitted as the required information is either
not present, is not present in sufficient amounts, or the information
required therein is included in the financial statements or notes
thereto.
List of Exhibits
(3) (a) - The Restated Articles of Incorporation of Empire
) (Incorporated by reference to Exhibit 4(a) to Registration
Statement No. 33-54539 on Form S-3).
(b) - By-laws of Empire as amended 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
among Empire, The Bank of New York and State Street Bank
and Trust Company of Missouri, N.A. (Incorporated by
reference to Exhibits B(1) and B(2) to Form 10, File No. 1-
3368).
(b) - Third Supplemental Indenture to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 2(c) to
Form S-7, File No. 2-59924).
(c) - Sixth through Eighth Supplemental Indentures to Indenture of
Mortgage and Deed of Trust (Incorporated by reference to
Exhibit 2(c) to Form S-7, File No. 2-59924).
(d) - Fourteenth Supplemental Indenture to Indenture of Mortgage
and Deed of Trust (Incorporated by reference to Exhibit
4(f) to Form S-3, File No. 33-56635).
(e) - Seventeenth Supplemental Indenture dated as of December 1,
1990 to Indenture of Mortgage and Deed of Trust
(Incorporated by reference to Exhibit 4(j) to Annual Report
on Form 10-K for year ended December 31, 1990, File No. 1-
3368).
(f) - 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 Registration
Statement No. 33-56635 on Form S-3).
(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) Indenture for Unsecured Debt Securities, dated as of
September 10, 1999 between Empire and Wells Fargo Bank
Minnesota, National Association (Incorporated by reference
to Exhibit 4(v) to Registration Statement No. 333-87015 on
Form S-3).
(r) - Securities Resolution No. 1, dated as of November 16, 1999,
of Empire under the Indenture for Unsecured Debt
Securities.*
(s) - Securities Resolution No. 2, dated as of February 22, 2001,
of Empire under the Indenture for Unsecured Debt
Securities.*
(t) - Rights Agreement dated as of April 27, 2000 between Empire
and Mellon Investor Services LLC (Incorporated by reference
to Exhibit 4 to Form 10-Q for the quarter ended March 31,
2000, File No. 1-3368).
(10)(a) - 1996 Stock Incentive Plan (Incorporated by reference to
Exhibit 4.1 to Form S-8, File No. 33-64639).
(b) - Management Incentive Plan (A description of this Plan is
incorporated by reference to page 5 of Empire'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.*
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
(a) In a current report dated December 7, 2000, Empire filed, under
Item 5. "Other Events," a press release concerning an order
from the Administrative Law Judge of the Arkansas Public
Service Commission relating to Empire's proposed merger with
UtiliCorp United Inc.
(b) In a current report dated December 12, 2000, Empire filed,
under Item 5. "Other Events," a press release concerning
orders from the Arkansas Public Service Commission and the
Corporation Commission of the State of Oklahoma relating to
Empire's proposed merger with UtiliCorp United Inc.
(c) In a current report dated December 29, 2000, Empire filed,
under Item 5. "Other Events," a press release concerning an
order from the Missouri Public Service Commission relating to
Empire's proposed merger with UtiliCorp United Inc.
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 2000, 1999 and 1998
Balance Additions Deductions from Balance
At Charged to Other Accounts reserve at
Beginning Charged to close of
of period income Description Amt. Description Amt. period
Year ended
December 31, 2000:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written off written off
Uncollectible
accounts $ 371,946 $1,283,268 $119,293 $ 807,297 $ 967,209
Reserve not
shown separately
in balance sheet: Property, plant
Injuries and & equipment and Claims and
damages Reserve clearing accounts expenses
(Note A) $1,000,000 $ 722,200 $722,200 $1,044,400 $1,400,000
Year ended
December 31, 1999:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written off written off
Uncollectible $275,876 $ 580,873 $372,955 $ 857,758 $ 371,946
accounts
Reserve not
shown separately
in balance sheet: Property, plant
Injuries and & equipment and Claims and
damages reserve clearing accounts expenses
(Note A) $1,314,461 $407,163 $407,163 $1,128,787 $1,000,000
Year ended
December 31, 1998:
Reserve deducted Recovery of
from assets: amounts
Accumulated previously Accounts
provision for written off written off
Uncollectible $278,741 $586,000 $448,718 $1,037,583 $275,876
accounts
Reserve not
shown separately
in balance sheet: Property, plant
Injuries and & equipment and Claims and
dmages Reserve clearing accounts expenses
(Note A) $1,311,995 $580,832 $530,011 $1,108,377 $1,314,461
NOTE A: This reserve is provided for workers' compensation, certain
postemployment benefits and public liability damages. Empire at
December 31, 2000 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 9, 2001
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.
M. W. MCKINNEY Date
M. W. McKinney, President and Director
(Principal Executive Officer)
D. W. GIBSON
D. W. Gibson, Vice President-Finance
(Principal Financial Officer)
D. L. COIT
D. L. Coit, Controller and Assistant Treasurer and Assistant Secretary
(Principal Accounting Officer)
V. E. BRILL*
V. E. Brill, Director
M. F. CHUBB, JR.*
M. F. Chubb, Jr., Director
R. D. HAMMONS*
R. D. Hammons, Director
March 9, 2001
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
D. W. GIBSON
*By...................................
(D. W. Gibson, As attorney in fact for
each of the persons indicated)