UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X Quarterly report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the quarterly period ended March 31, 1999 or
Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from ______________ to
____________.
Commission file number: 1-3368
THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Kansas 44-0236370
(State of Incorporation) (I.R.S. Employer
Identification No.)
602 Joplin Street, Joplin, Missouri 64801
(Address of principal executive offices) (zip code)
Registrant's telephone number: (417) 625-5100
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 ___
Common stock outstanding as of April 30, 1999: 17,179,454 shares.
THE EMPIRE DISTRICT ELECTRIC COMPANY
INDEX
Page Number
Part I - Financial Information:
Item 1. Financial Statements:
a. Statement of Income 3
b. Balance Sheet 5
c. Statement of Cash Flows 6
d. Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 8
Recent Developments 8
Results of Operations 8
Liquidity and Capital Resources 12
Year 2000 14
Forward Looking Statements 17
Item 3. Quantitative and Qualitative Disclosures About 17
Market Risk
Part II - Other Information:
Item 1. Legal Proceedings - (none)
Item 2. Changes in Securities - (none)
Item 3. Defaults Upon Senior Securities - (none)
Item 4. Submission of Matters to a Vote of Security Holders 18
Item 5. Other Information 18
Item 6. Exhibits and Reports on Form 8-K 18
Signatures 19
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
STATEMENT OF INCOME (UNAUDITED)
Three Months Ended
March 31,
1999 1998
Operating revenues:
Electric $ 54,491,652 $ 51,146,349
Water 250,461 241,891
54,742,113 51,388,240
Operating revenue deductions:
Operating expenses:
Fuel 9,232,210 6,151,704
Purchased power 11,008,095 14,485,249
Other 8,087,415 7,398,425
Total operating expenses 28,327,720 28,035,378
Maintenance and repairs 3,892,917 4,078,515
Depreciation and amortization 6,418,819 6,167,602
Provision for income taxes 2,937,570 1,954,840
Other taxes 3,161,259 3,092,132
44,738,285 43,328,467
Operating income 10,003,828 8,059,773
Other income and deductions:
Allowance for equity funds used 30,521 -
during construction
Interest income 40,959 25,267
Other - net (99,497) (196,650)
(28,017) (171,383)
Income before interest charges 9,975,811 7,888,390
Interest charges:
First mortgage bonds 4,618,614 4,145,292
Commercial paper 200,366 396,916
Allowance for borrowed funds used (163,506) (73,205)
during construction
Other 82,584 78,889
4,738,058 4,547,892
Net income 5,237,753 3,340,498
Preferred stock dividend requirements 599,180 604,085
Net income applicable to common stock $ 4,638,573 $ 2,736,413
Weighted average number of common 17,129,470 16,794,641
shares outstanding
Basic and diluted earnings per
weighted average share of
common stock $ 0.27 $ 0.16
Dividends per share of common stock $ 0.32 $ 0.32
See accompanying Notes to Financial Statements.
STATEMENT OF INCOME (UNAUDITED)
Twelve Months Ended
March 31,
1999 1998
Operating revenues:
Electric $242,146,134 $218,396,467
Water 1,066,031 997,850
243,212,165 219,394,317
Operating revenue deductions:
Operating expenses:
Fuel 44,956,571 35,481,195
Purchased power 44,095,387 49,039,282
Other 32,661,071 30,134,395
Total operating expenses 121,713,029 114,654,872
Maintenance and repairs 17,337,273 13,889,831
Depreciation and amortization 25,231,853 24,006,872
Provision for income taxes 17,172,730 13,439,007
Other taxes 12,441,448 11,455,023
193,896,333 177,445,60
Operating income 49,315,832 41,948,712
Other income and deductions:
Allowance for equity funds used 39,459 150,475
during construction
Interest income 279,493 132,136
Other - net (743,404) (528,264)
(424,452) (245,653)
Income before interest charges 48,891,380 41,703,059
Interest charges:
First mortgage bonds 18,347,154 16,590,133
Commercial paper 463,192 1,418,270
Allowance for borrowed funds used (490,345) (636,761)
during construction
Other 350,785 322,756
18,670,786 17,694,398
Net income 30,220,594 24,008,661
Preferred stock dividend requirements 2,406,879 2,416,340
Net income applicable to common stock $ 27,813,715 $ 21,592,321
Weighted average number of common 17,015,264 16,682,474
shares outstanding
Basic and diluted earnings per
weighted average share of
common stock $ 1.64 $ 1.29
Dividends per share of common stock $ 1.28 $ 1.28
See accompanying Notes to Financial Statements.
BALANCE SHEET
March 31,
1999 December 31,
(Unaudited) 1998
ASSETS
Utility plant, at original cost:
Electric $841,665,511 $832,484,754
Water 6,427,604 6,398,086
Construction work in progress 20,420,168 16,701,068
868,513,283 855,583,908
Accumulated depreciation 289,875,504 283,337,538
578,637,779 572,246,370
Current assets:
Cash and cash equivalents 7,620,578 2,492,716
Accounts receivable - trade, net 13,048,785 13,645,641
Accrued unbilled revenues 5,421,392 6,218,889
Accounts receivable - other 1,542,281 1,590,536
Fuel, materials and supplies 16,928,298 15,704,678
Prepaid expenses 531,882 929,447
45,093,216 40,581,907
Deferred charges:
Regulatory assets 35,642,426 35,999,139
Unamortized debt issuance costs 3,596,138 3,660,800
Other 1,537,617 805,568
40,776,181 40,465,507
Total Assets $664,507,176 $653,293,784
CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value,
17,170,977 and 17,108,799 shares
issued and outstanding,
respectively $ 17,170,977 $ 17,108,799
Capital in excess of par value 158,484,404 156,975,596
Retained earnings (Note 2) 54,866,496 55,706,779
Total common stockholders' equity 230,521,877 229,791,174
Preferred stock 32,901,800 32,901,800
Reacquired capital stock (267,537) (267,537)
Long-term debt 246,103,704 246,092,905
509,259,844 508,518,342
Current liabilities:
Accounts payable and accrued 12,554,653 17,096,272
liabilities
Commercial paper 22,000,000 14,500,000
Customer deposits 3,469,247 3,438,987
Interest accrued 7,174,686 4,113,300
Taxes accrued, including income 4,103,966 -
taxes
49,302,551 39,148,559
Noncurrent liabilities and deferred
credits:
Regulatory liability 16,121,907 16,400,125
Deferred income taxes 74,421,977 73,760,362
Unamortized investment tax credits 8,280,710 8,391,000
Postretirement benefits other than 4,480,696 4,463,883
pensions
Other 2,639,490 2,611,513
105,944,780 105,626,883
Total Capitalization and $664,507,176 $653,293,784
Liabilities
See accompanying Notes to Financial Statements.
STATEMENT OF CASH FLOWS (UNAUDITED)
Three Months Ended
March 31,
1999 1998
Operating activities:
Net income $ 5,237,753 $ 3,340,498
Adjustments to reconcile net income
to cash flows:
Depreciation and amortization 7,224,853 6,990,595
Pension income (665,721) (285,000)
Deferred income taxes, net 438,847 202,608
Investment tax credit, net (110,290) (71,340)
Allowance for equity funds used (30,521) -
during construction
Issuance of common stock for 401(k) 196,515 178,618
plan
Other - 54,247
Cash flows impacted by changes in:
Accounts receivable and accrued 1,442,608 1,176,876
unbilled revenues
Fuel, materials and supplies (1,223,620) (3,313,369)
Prepaid expenses and deferred (334,484) 115,116
charges
Accounts payable and accrued (4,541,620) (290,627)
liabilities
Customer deposits, interest and 7,195,612 6,332,691
taxes accrued
Other liabilities and other 710,512 (18,876)
deferred credits
Net cash provided by operating 15,540,444 14,412,037
activities
Investing activities:
Construction expenditures (13,239,538) (9,145,043)
Allowance for equity funds used 30,521 -
during construction
Net cash used in investing activities (13,209,017) (9,145,043)
Financing activities:
Proceeds from issuance of common 1,374,471 1,223,101
stock
Dividends (6,078,036) (5,975,736)
Net proceeds from short-term 7,500,000
borrowings
Net cash used in financing activities 2,796,435 (4,752,635)
Net increase (decrease) in cash and 5,127,862 514,359
cash equivalents
Cash and cash equivalents at beginning 2,492,716 2,545,282
of period
Cash and cash equivalents at end of $ 7,620,578 $ 3,059,641
period
See accompanying Notes to Financial Statements.
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
Note 1 - Summary of Significant Accounting Policies
The accompanying interim financial statements do not include
all disclosures included in the annual financial statements and
therefore should be read in conjunction with the financial
statements and notes thereto included in the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1998.
The information furnished reflects all adjustments, consisting
only of normal recurring adjustments, which are in the opinion of
the Company necessary to present fairly the results for the interim
periods presented.
Note 2 - Retained Earnings
First
Quarter
1999
Balance at January 1, 1999 $55,706,779
Changes January 1 through March 31:
Net Income 5,237,753
Quarterly cash dividends on common stock:
- $0.32 per share (5,478,855)
Quarterly cash dividends on preferred stock:
8-1/8% cumulative - $0.203125 per share (503,953)
5% cumulative - $0.125 per share (47,728)
4-3/4% cumulative - $0.11875 per share (47,500)
Total changes January 1 through March 31 (840,283)
Balance at March 31, 1999 $54,866,496
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
RECENT DEVEOPMENTS
The Company and UtiliCorp United Inc., a Delaware corporation
("UtiliCorp"), have entered into an Agreement and Plan of Merger,
dated as of May 10, 1999 (the "Merger Agreement"), which provides
for a merger of the Company with and into UtiliCorp, with UtiliCorp
being the surviving corporation (the "Merger"). Under the terms of
the Merger Agreement, UtiliCorp is offering $29.50 for each share
of Common Stock of the Company, payable in UtiliCorp common stock
or cash. UtiliCorp also will assume approximately $260 million of
existing debt of the Company, including its first mortgage bonds.
The Merger Agreement contains a collar provision under which the
value of the merger consideration per share will decrease if
UtiliCorp's common stock is below $22 per share preceding the
closing and will increase if UtiliCorp's common stock is above $26
per share preceding the closing. Stockholders of the Company may
elect to take cash or stock, but total cash paid to stockholders
will be limited to no more than 50% of the total Merger
consideration, and the UtiliCorp common stock that may be issued in
the Merger is limited to 19.9% of the then outstanding common stock
of UtiliCorp.
The Merger, which was unanimously approved by the Boards of
Directors of the constituent companies, is expected to close after
all of the conditions to the consummation of the Merger are met or
waived. The Merger is conditioned, among other things, upon
approval of stockholders of the Company, approvals of federal
regulatory agencies and approvals of state regulatory authorities
in states where the combined company will operate. Other
conditions in the Merger Agreement require the Company to redeem
all of its outstanding preferred stock (approximately $33 million)
according to its terms prior to the closing and to obtain the
consent of holders of its outstanding first mortgage bonds to a
modification of a dividend limitation provision relating to
successor corporations which is contained in the Company's
Indenture of Mortgage and Deed of Trust, dated as of September 1,
1944, as amended and supplemented, pursuant to which its first
mortgage bonds are issued.
Based in Kansas City, Missouri, UtiliCorp is an international
energy company with more than 3 million electric and natural gas
network customers across the United States and in Canada,
Australia, New Zealand and the United Kingdom. Its Missouri Public
Service division serves 250,000 electric and gas customers in west
and central Missouri.
The Merger Agreement and the press release issued in
connection therewith are filed as Exhibits 2 and 99, respectively,
to this Quarterly Report on Form 10-Q and are incorporated herein
by reference. The description of the Merger Agreement set forth
herein does not purport to be complete and is qualified in its
entirety by the provisions of the Merger Agreement.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
results of operations for the three-month and twelve-month periods
ended March 31, 1999, compared to the same periods ended March 31,
1998.
Operating Revenues and Kilowatt-Hour Sales
Of the Company's total electric operating revenues during the
first quarter of 1999, approximately 45% were from residential
customers, 28% from commercial customers, 17% from industrial
customers, 4% from wholesale on-system customers and 2% 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 Revenue
Twelve Twelve
First Months First Months
Quarter Ended Quarter Ended
Residential 6.5% 9.6% 6.5% 12.7%
Commercial 7.0 7.5 7.2 10.4
Industrial 6.6 3.1 6.0 6.1
Wholesale On- 0.5 7.8 (2.4) 9.2
System
Total 6.1 7.0 6.1 10.5
System
Residential and commercial Kwh sales and revenues were up
during the first quarter of 1999 compared to the first quarter of
1998 despite warmer temperatures during February and March of 1999.
Although total heating degree days (the number of degrees that the
average temperature for that period was below 65 F) for the first
quarter of 1999 were 9% less than the same period last year,
increases of 1.8% in the average number of residential customers
served and 2.0% in the average number of commercial customers
served compared to a year ago contributed to the increased Kwh
sales and revenues. In addition, revenues and Kwh sales were
positively impacted by a change in the estimation of periodic loss
factors used to calculate unbilled revenues. The estimation of
these loss factors was modified from using a fixed annual average
factor to using a variable factor that more closely approximates
the actual monthly activity. Revenues were also positively
impacted by the annual rate increase of $358,848 (6.6%) granted by
the Arkansas Public Service Commission ("Arkansas Commission")
effective August 24, 1998.
Industrial Kwh sales and revenues, which are not particularly
weather sensitive, were up during the first quarter of 1999 when
compared to the same period last year due to continuing increases
in business activity throughout the Company's service territory.
Industrial revenues were also positively impacted by the 1998
Arkansas rate increase.
On-system wholesale Kwh sales increased during the first
quarter of 1999 reflecting the continuing increases in business
activity described above. Revenues associated with those sales
decreased despite the corresponding increase in Kwh sales as a
result of the operation of the fuel adjustment clause applicable to
these FERC regulated sales. This clause permits changes in fuel
and purchased power costs to be passed along to customers without
the need for a rate proceeding.
For the twelve months ended March 31, 1999, Kwh sales to and
revenue from the Company's residential and commercial customers
increased, reflecting the warmer temperatures experienced during
the second and third quarters of 1998. Industrial and on-system
wholesale sales continued to grow due to strong business activity
in the Company's service territory. Residential, commercial and
industrial revenues for the twelve months ended March 31, 1999 were
also positively impacted by twelve months of the Missouri rate
increases that were effective July 28, 1997 and September 19, 1997
as well as the 1998 Arkansas rate increase discussed above.
Off-System Transactions
In addition to sales to its own customers, the Company also
sells power to other utilities as available and also provides
transmission service through its system for transactions between
other energy suppliers. During the first quarter of 1999, revenues
from such off-system transactions were approximately $1.6 million,
compared with approximately $1.3 million during the first quarter
of 1998. For the twelve months ended March 31, 1999, revenues from
such off-system transactions were approximately $8.6 million as
compared to $8.3 million for the twelve months ended March 31,
1998. The margin on such off-system sales is lower than on sales to
the Company's on-system customers. In addition, pursuant to an
order issued by the FERC and subsequent tariffs filed by the
Company and the Southwest Power Pool ("SPP"), these off-system
sales have been opened up to competition. The Company cannot
predict, however, the effect such competition will have on its
future operations or financial results. Reference is made to the
Company's Annual Report on Form 10-K for the year ended December
31, 1998 under the caption "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Competition" for
more information on these open-access tariffs.
The Company is a member of the SPP, a regional division of the
North American Electric Reliability Council, which requires its
members to maintain reserve margins of 12.00%. The Company is also
a member of the Western Systems Power Pool ("WSPP"), a marketing
pool that provides agreements that facilitate the purchase and sale
of wholesale power among members. Most of the United States
electric utilities are now parties to this agreement.
On February 8, 1999, the Company filed a petition with the
FERC seeking approval to sell power at market-based rates. In this
filing, the Company also requested approval for a rate schedule
that would allow the Company to sell, assign or otherwise transfer
transmission capacity that it holds on other systems or on its own
system. This petition was approved by the FERC on April 9, 1999.
The primary benefit of the market-based power tariff is that
it will remove the rate cap on power that is sold under any of the
WSPP schedules that previously restricted the Company to a margin
of $22 per Mwh above cost. This tariff would apply to off-system
sales by the Company to other utilities and power brokers. This
change could result in an increase in revenue during the summer
season when power is selling at higher prices. The revenue impact
of this change, however, is not expected to be significant during
any season other than the summer season. The magnitude of any such
increase will be affected by the availability of purchased power in
the bulk power market, generation fuel costs and the requirements
of other electric systems during this season. As a result of its
inability to control or predict these factors, the Company cannot
currently predict the effect these tariffs will have on its future
operations or financial results.
Operating Revenue Deductions
During the first quarter of 1999, total operating expenses
increased approximately $0.3 million (1.0%) compared with the same
period last year. Purchased power costs decreased approximately
$3.5 million (24.0%) during the period, primarily due to increased
availability from the Asbury Plant in the first quarter as compared
to last year because of a timing difference in spring maintenance
outages. An outage at the Asbury Plant in January of 1998,
initially caused by a generator winding problem, was extended to
perform spring maintenance originally scheduled for the second
quarter. As a result, additional purchases of power were incurred
in the first quarter of 1998. The Asbury Plant began this year's
spring outage in early April and is scheduled to return to service
in early May. As a result of these timing differences in the
spring outages, purchased power costs could be greater during the
second quarter of 1999 as compared to the second quarter of 1998.
Total fuel costs increased approximately $3.1 million (50.1%)
during the first quarter of 1999 primarily reflecting the increased
generation from the Asbury Plant discussed above.
Other operating expenses increased approximately $0.7 million
(9.3%) during the period due primarily to higher general and
administrative costs. Maintenance and repair expense decreased
approximately $0.2 million (4.6%) during the quarter, primarily due
to the decreased first quarter expenses associated with the timing
differences of the Asbury maintenance outages. These decreased
expenses helped to offset approximately $1.0 million in expenses
incurred to repair storm damages resulting from a New Year's Day
ice storm that interrupted service to approximately 35,000 of the
Company's Missouri and Kansas customers over a three day period.
Depreciation and amortization expenses increased approximately
$0.3 million (4.1%) during the quarter due to increased levels of
plant and equipment placed in service. Total income taxes
increased $1.0 million (50.3%) during the first quarter of 1999 due
primarily to higher taxable income during the current period. Other
taxes increased slightly during the quarter.
During the twelve months ended March 31, 1999, total operating
expenses increased approximately $7.1 million (6.2%) compared to
the year ago period. Total purchased power costs were down
approximately $4.9 million (10.1%), primarily due to decreased
purchases of replacement energy due to the timing differences of
the Asbury Plant outages. Total fuel costs were up approximately
$9.5 million (26.7%) during the twelve month period due primarily
to greater availability and increased usage of the Company owned
generating facilities. Generation from the higher-cost gas-fired
combustion turbines at the State Line Power Plant and the Energy
Center increased during the second and third quarters of 1998 due
to increased customer demand resulting from warmer temperatures.
Other operating expenses increased approximately $2.5 million
(8.4%) during the twelve months ended March 31, 1999, compared to
the same period last year due primarily to higher general and
administrative and customer accounts expenses. Approximately $0.7
million of this increase was a one-time charge during 1998 due to
the initiation of the Directors Stock Unit Plan, a stock-based
retirement compensation program for the Company's Directors. The
remainder of the increase resulted from $0.9 million in increased
costs for outside services and a $0.9 million increase in costs for
the employee health care plan.
Maintenance and repair expenses increased approximately $3.4
million (24.8%) during the twelve months ended March 31, 1999,
compared to the prior period. This increase was primarily due to
the scheduled maintenance on the gas-fired combustion turbines at
the Energy Center and the State Line Power Plant during the fourth
quarter of 1998 and the five-year scheduled maintenance outage at
the Riverton Plant during the second quarter of 1998. Depreciation
and amortization expense increased approximately $1.2 million
(5.1%) due to increased levels of plant and equipment placed in
service. Total provision for income taxes increased $3.7 million
(27.8%) due to higher taxable income during the current period.
Other taxes increased $1.0 million (8.6%) due primarily to
increased property taxes.
Nonoperating Items
Total allowance for funds used during construction ("AFUDC")
increased slightly during the first quarter of 1999 as compared to
the same period last year, reflecting new construction beginning at
the State Line Power Plant. AFUDC decreased slightly during the
twelve months ended March 31, 1999 as compared to the year ago
period reflecting continuing lower levels of construction work in
progress following the completion of State Line Unit No. 2 in June
1997.
Other-net deductions decreased $0.1 million (49.4%) for the
first quarter of 1999 as compared to the first quarter of 1998,
reflecting increasing profit margins for the Company's non-
regulated fiber optics leasing venture. Other-net deductions
totaled approximately $0.7 million for the twelve-month period
ended March 31, 1999, a $0.2 million (40.7%) increase over the same
period last year. This increase was primarily due to one-time
startup costs for the Company's non-regulated ventures, such as
home security and fiber optics leasing. Interest income increased
for both periods, reflecting the higher balances of cash available
for investment.
Interest charges on first mortgage bonds increased $0.5
million (11.4%) during the first quarter of 1999 and $1.8 million
(10.6%) for the twelve months ended March 31, 1999 when compared to
the same periods last year due to the issuance of $50 million of
the Company's First Mortgage Bonds in April, 1998. These proceeds
were used to repay $23 million of the Company's First Mortgage
Bonds due May 1, 1998 and to repay short-term indebtedness,
including that incurred in connection with the Company's
construction program. As a result, commercial paper interest
decreased $0.2 million (49.5%) during the first quarter of 1999 and
$1.0 million (67.3%) for the twelve months ended March 31, 1999 due
to decreased usage of short-term debt for financing purposes.
Earnings
For the first quarter of 1999, earnings per share of common
stock were $0.27 compared to $0.16 during the first quarter of
1998. Earnings per share were up primarily due to increased sales
to all classes of customers as well as the decrease in purchased
power costs resulting from the increased availability of our own
generating units and the change in the estimation of the loss
factors used to calculate unbilled revenues. Earnings were also
positively impacted by the 1998 Arkansas rate increase.
Earnings per share for the twelve months ended March 31, 1999,
were $1.64 compared to $1.29 for the twelve months ended a year
earlier reflecting increased revenues resulting primarily from the
warm summer temperatures in the second and third quarters of 1998
as well as the 1997 Missouri rate increases, the 1998 Arkansas rate
increase and the change in the estimation of the loss factors used
to calculate unbilled revenues.
Competition
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. This freeze
applies only to rate increases and does not apply to any fuel
adjustment clause or energy cost recovery rider approved by the
Arkansas Commission, such as the one the Company has to recover its
fuel and purchased power costs.
Fuel
The Iatan Plant, which is jointly owned by Kansas City Power &
Light (70%), St. Joseph Light & Power Company (18%) and the Company
(12%), has a long-term contract expiring on December 31, 2003 with
the Thunder Basin Coal Company for low sulfur Western coal. This
contract was renegotiated on April 1, 1999. The Company's share of
the resulting savings will be approximately $0.6 million per year
for the remainder of the contract.
LIQUIDITY AND CAPITAL RESOURCES
The Company's construction-related expenditures totaled $13.2
million during the first quarter of 1999, compared to $9.1 million
for the same period in 1998. Approximately $5.6 million of these
expenditures during the first quarter of 1999 was related to
additions to the Company's distribution and transmission systems to
meet projected increases in customer demand and approximately $2.1
million of the first quarter's construction expenditures was
related to the Company's maintenance program for the gas-fired
combustion turbines at the Energy Center and State Line Power
Plant. An additional $2.2 million was related to the expansion
project at the State Line Power Plant described below. During the
first quarter of 1999, approximately 71% of construction
expenditures were satisfied internally from operations.
The Company announced on October 2, 1998 its plans for the
construction of a 350-megawatt addition to the State Line Power
Plant (the "State Line Project"). This State Line Project would
consist of adding an additional combustion turbine, two heat
recovery steam generators and a steam turbine and auxiliary
equipment to an already existing combustion turbine. Preparatory
work has begun and the State Line Project is projected to be
operational by June 2001. The Company announced on February 4, 1999
that it had entered into a Memorandum of Understanding which
contemplates entering into a joint ownership agreement under which
the Company would own an undivided 60% interest in the State Line
Project with Western Resources, Inc. owning the remainder. The
Company would also be entitled to 60% of the capacity of the State
Line Project. The Company would contribute its existing 152-
megawatt State Line Unit No. 2 combustion turbine to the State Line
Project, and as a result, upon commercial operation, the State Line
Project would provide the Company with 150 megawatts of additional
capacity. The total cost of the State Line Project is estimated to
be $185 million (of which $100 million, in addition to the transfer
of a portion of State Line Unit No. 2 and certain other property at
book value, is expected to be the Company's share).
In anticipation of executing definitive documentation with
Western Resources, Inc. (or one of its subsidiaries), the Company
has entered into contracts with Siemens-Westinghouse Power
Corporation for the provision of major components for the State
Line Project, with Black & Veatch Corporation for engineering and
management services for the State Line Project, and with Williams
Gas Pipeline Central for the transportation of natural gas to the
State Line Project. Westar Generating, Inc. (a subsidiary of
Western Resources, Inc.) agreed on April 30, 1999 to reimburse the
Company for 40% of expenditures made or to be made by the Company
in connection with the State Line Project, including all payments
made or to be made by the contracts listed above.
The Company's construction expenditures are expected to total
approximately $70.1 million in 1999, including approximately $29.9
million for new generating facilities at the State Line Project and
$18.0 million for additions to the Company's distribution system to
meet projected increases in customer demand.
The Company currently estimates that internally generated
funds will provide 56% of the funds required for the remainder of
its 1999 construction expenditures. As in the past, in order to
finance the additional amounts needed for such construction, the
Company intends to utilize short-term debt and sales of public
offerings of long-term debt or equity securities, including the
sale of the Company's common stock pursuant to its Dividend
Reinvestment Plan and Employee Stock Purchase Plan as well as
internally-generated funds. The Company will continue to utilize
short-term debt as needed to support normal operations or other
temporary requirements.
Following announcement of the Merger, the ratings for the
Company's 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, Standard & Poor's and Duff & Phelps
Credit Rating Company.
Year 2000
Year 2000 Background
Many existing computer programs use only two digits to
identify a year in the date field. These programs were designed
and developed without considering the impact of the upcoming
century change. As a result, computer systems may fail completely
or produce erroneous results unless corrective measures are taken.
The Company is engaged in an on-going project to identify, evaluate
and implement changes to both information technology ("IT") and non-
IT systems in order to achieve Year 2000 readiness. The Company
has also become a member of the Edison Electric Institute's Year
2000 Committee and the Electric Power Research Institute's Y2K
Embedded Systems Program in order to assist in the implementation
of its Year 2000 Readiness Plan. In addition, the Company is
participating in the North American Electric Reliability Council's
("NERC") efforts to prepare mission critical systems for Year 2000
readiness. NERC's target is to have all mission critical electric
power production, transmission, and delivery systems Year 2000
ready by June 30, 1999. The Company is working within that
framework and participated in an industry-wide Year 2000 drill on
April 9, 1999 with good results. Essential sites and facilities
included in the drill were the control area (dispatching), power
generation sites, interconnect transmission substations, and
transmission lines. The Company plans to participate in a second
industry-wide drill on September 9, 1999.
NERC's 1999 first quarter report to the Department of Energy
indicated that more than 75% of testing and repairing by the
Nation's utilities is now complete. NERC reported that "fewer than
3% of all components tested have required Y2K fixes and the errors
that have appeared have been mostly cosmetic or nuisance type
errors, such as incorrect dates in logs."
The Company is using a multi-step approach in achieving its
Year 2000 Readiness Plan. These steps include creating awareness
of the Year 2000 problem, forming a Year 2000 task force,
developing procedures for documenting Year 2000 readiness,
developing a methodology for the Year 2000 Readiness Plan and
testing and remediation of Year 2000 affected items pursuant to the
Year 2000 Readiness Plan. Developing the methodology for the Year
2000 Readiness Plan includes creating and implementing an ongoing
communication program with both internal and external parties,
performing an inventory of possible Year 2000 affected items,
assessing and prioritizing each such inventory item as to level of
criticality, scheduling testing and remediation of such items in
order of criticality, and developing contingency planning. The
management consulting firm of Sargent & Lundy has reviewed the
process involving the implementation of the Year 2000 Readiness
Plan as well as the plan itself. Recommendations based on their
independent findings will be implemented as a step of the Year 2000
Readiness Plan.
The Company has purchased a new financial management software
package from PeopleSoft that is Year 2000 ready. The package
includes financial accounting systems for general ledger, accounts
payable and asset management; purchasing and inventory; human
resource systems for benefits, time and labor, and payroll; as well
as systems for budgeting and project tracking. All of the systems,
with the exception of asset management and the human resource
systems, are now being utilized. The asset management system is
expected to begin operation in June 1999 and the human resource
systems are scheduled to begin operation in July 1999. In
addition, a new customer information system, Centurion, is being
developed internally which will be Year 2000 ready. Installation
of this system is expected to be completed by mid-1999. The
installation of these systems is anticipated to substantially
mitigate the Company's Year 2000 exposure.
State of Readiness
A task force has been appointed and is charged with
documenting and testing areas of the Company which may be affected
by the Year 2000. The targeted areas include general preparation,
power generation, energy management systems, telecommunications,
substation controls and system protection and business information
systems. Within each of these areas, the task force is examining
the status of IT systems, non-IT systems and third parties such as
vendors, customers and others with whom the Company does business.
The inventory of Year 2000 items was completed in September 1998.
Assessing and prioritizing each item within the Year 2000 inventory
as to the level of criticality was also completed in September
1998. The ongoing testing and remediation of the highest level of
critical items is scheduled to be completed by the end of the
second quarter of 1999. The Year 2000 task force will also develop
contingency plans in the event that unanticipated problems are
encountered. These plans are also scheduled to be completed during
the second quarter of 1999. The Company currently plans to
substantially complete its Year 2000 testing and compliance
projects by the end of the second quarter of 1999.
The status of each of the targeted areas undergoing testing is as
follows:
General Preparation. Scheduled upgrades to the telephone switch
are 75% complete with the final upgrades scheduled to be completed
in the second quarter of 1999. The testing of other items is
scheduled to be completed by the end of the second quarter of 1999.
Power Generation. Assessment, inventory and testing are complete
at all plants. There are a few items, mostly non-critical, that
need to be remediated at the plants. This will be completed as
soon as possible.
Energy Management Systems. The Company is in the process of
installing major upgrades to its Energy Management System hardware
and software as a result of Year 2000 related problems observed
during preliminary system testing. These upgrades are anticipated
to be completed by the end of the second quarter of 1999. The
Company has obtained readiness certifications for most of the other
related components and will conduct its own tests on components
critical to the operations of the Energy Management System and
other related systems. Year 2000 related testing of these
components is expected to be completed by July 31, 1999.
Telecommunications. The Company has worked with suppliers and
manufacturers to obtain readiness certifications for its various
telecommunications systems and components. The Company plans to
complete the testing of critical systems and components by the end
of the second quarter of 1999.
Substation Controls and System Protection. Testing of transmission
and distribution equipment to date has identified a minor amount of
equipment that will require Year 2000 remediation. That equipment
will be replaced by the end of the second quarter of 1999.
Business Information Systems. As previously stated, the new
financial management software package from PeopleSoft is Year 2000
ready and the new Centurion customer information system, when
completed, is expected to be Year 2000 ready. As a result of the
implementation of the new software packages, several hardware
changes are being required throughout the Company, delaying testing
of the remaining systems. Currently, the testing of these systems
is 10% complete with the target date for the completion of testing
being mid-1999.
Third Parties. The Company has requested readiness certifications
from third party vendors for all of its core applications and
operating systems. However, all critical applications will be
tested regardless of whether a certification of readiness has been
obtained. In addition, the Company is contacting other third
parties with whom the Company does business (such as major
customers, power pools, power suppliers, transmission providers and
telecommunications providers) in order to assess their states of
readiness. This initial contact phase was completed at the end of
1998. The Company will continue to monitor the progress of these
third parties throughout the remainder of 1999. The Company is
conducting face to face meetings with its most critical suppliers
and its largest customers and is corresponding in writing with its
other suppliers and customers.
Year 2000 Costs
The Company currently estimates that total costs (which
include the costs of the new financial management software package
and the new customer information system) to update all systems for
Year 2000 readiness will be approximately $3.7 million, of which
approximately $2.8 million have been incurred and capitalized as of
March 31, 1999 and $0.5 million have been incurred and expensed.
Of these capitalized costs, $0.5 million were included in the 1998
capital budget. Costs for specific Year 2000 remediation projects
will be charged to expense while costs to replace software for
business purposes other than addressing Year 2000 issues will be
capitalized.
Risk Assessment and Contingency Plans
At this time, the Company believes the most reasonably likely
worst case scenario would result from fuel constraints due to
supply failure(s), specifically natural gas, oil, water or other,
with the most likely being natural gas. The Company is assessing
the risk of this scenario and is formulating contingency plans,
currently scheduled to be completed during the second quarter of
1999, to mitigate the potential impact. As a part of these plans,
the Company is increasing its supply of coal at the Asbury and
Riverton Power Plants. Under normal conditions, the Company's
targeted coal inventory supply at both plants is approximately 45
days. As of April 30, 1999, the supply of western coal at the
Asbury Plant was approximately 85 days and the supply of blend coal
was approximately 125 days, while the supply of western coal at the
Riverton Plant was approximately 85 days and the supply of blend
coal was approximately 49 days. In addition, the Company has the
ability to switch the fuel used by the combustion turbines at the
Energy Center and State Line Plants from natural gas to diesel fuel
should a disruption in natural gas delivery occur. The Company's
Year 2000 task force has formed a contingency planning team which
will follow guidelines established by the NERC to formalize a plan
with respect to the above worst case scenario and other
contingencies which may develop by the end of the second quarter of
1999.
The Company's Readiness Plan is designed to provide corrective
action with respect to Year 2000 risks. If the Plan is not
successfully carried out in a timely manner, or if unforeseen
events occur, Year 2000 problems could have a material adverse
impact on the Company. Management does not expect such problems to
have such an effect on its financial position or results of
operations.
FORWARD LOOKING STATEMENTS
Certain matters discussed in this 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 Project), earnings,
competition, litigation, rate and other regulatory matters,
liquidity and capital resources, Year 2000 readiness (including
estimated costs, completion dates, risks and contingency plans) and
accounting matters. Actual results in each case could differ
materially from those currently anticipated in such statements, by
reason of factors such as the cost and availability of purchased
power and fuel; electric utility restructuring, including ongoing
state and federal activities; weather, business and economic
conditions; legislation; regulation, including rate relief and
environmental regulation (such as NOx regulation); competition;
including the impact of deregulation on off-system sales; and other
circumstances affecting anticipated rates, revenues and costs.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk. The Company is exposed to changes in
interest rates as a result of significant financing through its
issuance of fixed-rate debt, commercial paper and preferred stock.
The Company manages its interest rate exposure by limiting its
variable-rate exposure to a certain percentage of total
capitalization, as set by policy, and by monitoring the effects of
market changes in interest rates
If market interest rates average 1% more in 1999 than in 1998,
the Company's interest expense would increase, and income before
taxes would decrease, by approximately $220,000. This amount has
been determined by considering the impact of the hypothetical
interest rates on the Company's commercial paper balances as of
March 31, 1999. These analyses do not consider the effects of the
reduced level of overall economic activity that could exist in such
an environment. In the event of a significant change in interest
rates, management would likely take actions to further mitigate its
exposure to the change. However, due to the uncertainty of the
specific actions that would be taken and their possible effects,
the sensitivity analysis assumes no changes in the Company's
financial structure.
Commodity Price Risk. The Company is exposed to the impact of
market fluctuations in the price and transportation costs of coal,
natural gas, and electricity and employs established policies and
procedures to manage its risks associated with these market
fluctuations. At this time none of the Company's commodity
purchase or sale contracts meet the definition of financial
instruments.
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
(a) The annual meeting of Common Stockholders was held on April
22, 1999.
(b) The following persons were re-elected Directors of the Company
to serve until the 2002 Annual Meeting of Stockholders:
M. F. Chubb (13,401,721 votes for; 194,407 withheld
authority).
R. L. Lamb (13,398,048 votes for; 198,080 withheld
authority).
R. E. Mayes (13,389,638 votes for; 206,490 withheld
authority).
The term of office as Director of the following other
Directors continued after the meeting: V. E. Brill, Jr., R. D.
Hammons, J. R. Herschend, R. C. Hartley, F. E. Jefferies, M.
W. McKinney, and M. M. Posner.
Item 5. Other Information.
At March 31, 1999, the Company's ratio of earnings to fixed
charges, and ratio of earnings to fixed charges and preferred stock
dividend requirements, were 3.44x and 2.89x, respectively. See
Exhibit (12) hereto.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
(2)Agreement and Plan of Merger, dated as of May 10, 1999, by
and between the Company and UtiliCorp United Inc.
(12) Computation of Ratios of Earnings to Fixed Charges
and Earnings to Combined Fixed Charges and Preferred Stock
Dividend Requirements.
(27) Financial Data Schedule for March 31, 1999
(99) Joint Press Release, dated May 11, 1999, of the
Company and UtiliCorp United Inc.
SIGNATURES
Pursuant to the requirements 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
Registrant
By /s/ R. B. Fancher
R. B. Fancher
Vice President - Finance
By /s/ G. A. Knapp
G. A. Knapp
Controller and Assistant Treasurer
May 14, 1999
EXHIBIT (12)
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND
EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDEND
REQUIREMENTS
Twelve
Months Ended
March 31,
1999
Income before provision for income taxes and $ 66,494,732
fixed charges (Note A)
Fixed charges:
Interest on first mortgage bonds $ 17,496,910
Amortization of debt discount and expense less 850,244
premium
Interest on short-term debt 463,191
Other interest 350,785
Rental expense representative of an interest 165,939
factor (Note B)
Total fixed charges 19,327,069
Preferred stock dividend requirements:
Preferred stock dividend requirements not 2,329,539
deductible for tax purposes
Ratio of income before provision for incomes 1.561
taxes to net income
Nondeductible dividend requirements 3,636,410
Deductible dividends 78,036
Total preferred stock dividend requirements 3,714,446
Total combined fixed charges and preferred stock $ 23,041,515
dividend requirements
Ratio of earnings to fixed charges 3.44x
Ratio of earnings to combined fixed charges and
preferred stock
dividend requirements 2.89x
NOTE A:For the purpose of determining earnings in the calculation of the ratio,
net income has been increased by the provision for income taxes,
non-operating income taxes and by the sum of fixed charges as shown
above.
NOTE B: One-third of rental expense (which approximates the interest factor).