<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934.
For the fiscal year ended December 31, 1999
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED).
For the transition period from to
Commission file number 1-3576
ST. JOSEPH LIGHT & POWER COMPANY
(Exact name of registrant as specified in its charter)
State of Missouri 44-04l9850
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
520 Francis Street, P. O. Box 998, St. Joseph, Missouri
(Address of principal executive offices)
64502-0998
(Zip Code)
Registrant's telephone number, including area code (816) 233-8888
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
- ------------------------------- -------------------------
Common Stock, without par value 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 ]
The aggregate market value of the registrant's outstanding
common stock, based on the closing price therefor on the New York
Stock Exchange at February 29, 2000, was $167,417,847.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of the latest practicable
date.
Common Stock, without par value 8,267,548 shares
- ------------------------------- -----------------------------
(Class) (Outstanding at February 29,2000)
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the 1999 Annual Report to Shareholders are
incorporated by reference into Parts I, II and IV.
Portions of the 2000 Definitive Proxy Statement for the 2000
annual meeting are incorporated by reference into Part III,
excluding therefrom the sections titled "Report of Compensation
Committee" and "Cumulative Total Shareholder Return."
The 1999 Annual Report to Shareholders and the 2000 Definitive
Proxy Statement will be mailed to shareholders on or about April
10, 2000.
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PART I
ITEM 1 - BUSINESS.
St. Joseph Light & Power Company is a Missouri corporation,
incorporated in 1895. SJLP Inc., its wholly owned subsidiary, was
formed in September 1996 to pursue investments in non-utility
areas. Collectively, these entities are referred to as the
"Company."
The Company is engaged primarily in the generation,
transmission and distribution of electric energy to customers in
its ten-county service territory in northwest Missouri. It
supplies this service in St. Joseph, the headquarters city, and
52 other incorporated communities and the intervening rural
territory. The service area contains approximately 3,300 square
miles. At December 31, 1999, there were approximately 63,000
electric customers. In 1999, electric revenues accounted for 75%
of total operating revenues. Natural gas for residential,
commercial and industrial purposes is provided to customers in
Maryville, a state university town of about 10,000, and 14 other
smaller communities in northwest Missouri. Natural gas revenues
accounted for 4% of total operating revenues in 1999. Currently
there are about 6,400 natural gas customers. The Company
supplies industrial steam to six customers in St. Joseph.
Industrial steam revenues accounted for 5% of total operating
revenues in 1999.
Effective May 31, 1997, SJLP Inc. acquired a controlling
interest in Percy Kent, a manufacturer of multiwall and small
paper bags, primarily for food products, agricultural products,
specialty chemicals, pet foods and other consumer packaging
companies throughout the United States. In 1999, manufacturing
revenues accounted for 16% of total operating revenues.
On March 4, 1999, the Company and UtiliCorp United Inc.
entered into an Agreement and Plan of Merger to form a strategic
business combination. Under terms of the Agreement, each share
of common stock of the Company will be valued at $23.00 per share
when exchanged for UtiliCorp United Inc. common stock. The
Agreement was approved by a vote of the Company's shareholders at
a special meeting in 1999, and by the Public Utility Commissions
of Colorado, West Virginia, Iowa and Minnesota. The transaction
is subject to several additional closing conditions, including
approval by the Federal Energy Regulatory Commission, the
Department of Justice, the Federal Communications Commission, and
the Missouri Public Service Commission (PSC). The PSC has
scheduled hearings in July 2000. Management expects the merger
to be completed in the fall of 2000.
SOURCES AND AVAILABILITY OF RAW MATERIALS.
The Company's principal fuel for electric generation is coal.
Small amounts of natural gas and oil are also used. During 1999,
fuels utilized for electric generation consisted of 90% coal and
10% gas and oil.
The Company, Kansas City Power & Light Company (KCP&L) and The
Empire District Electric Company (EDE), the joint owners of the
Iatan plant, have a twenty-year agreement with a Wyoming mine for
low sulfur western coal. The agreement provides for approximately
two million tons of coal per year through 2003. The coal is
delivered by rail under an agreement, which extends through 2000.
The remaining coal requirements at the Iatan plant are met with
short-term purchase agreements.
The Lake Road plant now burns 100% low-sulfur western coal
with the majority supplied by a Wyoming mine under a two-year
agreement that expires in 2001. The Company also has a one-year
contract to supply additional western coal in 2000. Management
anticipates meeting remaining 2001 coal requirements for the
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<PAGE>
plant with present inventory, short-term contracts and spot
purchases. The Company's rail contract provides for a minimum of
180,000 tons per year and expires at the end of 2001.
Lake Road natural gas requirements are met with purchases from
regional suppliers and transported under the industrial tariffs
of Missouri Gas Energy as an interruptible customer. The Company
meets all of its oil requirements through short-term agreements
and spot purchases.
The Company acquires its natural gas for resale on the open
market and with short-term contracts. An agreement with ANR
Pipeline Company provides natural gas storage and transportation
services until 2003. Management believes the arrangement is
sufficient to fulfill its natural gas requirements.
FRANCHISES.
The Company currently holds non-exclusive franchises for its
electric utility operations in substantially all of the
incorporated portions of its service area. The Company holds a
perpetual electric franchise without limitation of time in St.
Joseph. Franchises in 51 additional incorporated municipalities
expire in various years until 2020. One small community is
served without a franchise.
The Company holds gas franchises in each of the 15 communities
served, expiring in various years until 2020.
COMPETITION.
There are three rural electric cooperatives (RECs) serving
approximately 30,000 customers within the Company's service area.
These RECs purchase their total power requirements from
generating and transmission cooperatives which are financed
partially by government loans or grants.
Two municipally owned electric distribution systems are
located in the Company's territory serving approximately 900
customers.
The Company's rates are significantly lower than the RECs and
municipally owned systems in the area and also compare very
favorably with other investor-owned utilities in the region.
Further competition information is incorporated by reference to
Management's Discussion and Analysis of Financial Condition and
Results of Operations in the 1999 Annual Report to Shareholders,
pages 5-12, which is Exhibit 13 hereto.
FINANCIAL INFORMATION ABOUT SEGMENTS OF BUSINESS.
This information is incorporated by reference to Note 8 of the
Notes to Consolidated Financial Statements in the 1999 Annual
Report to Shareholders, pages 25-26, which is Exhibit 13 hereto.
ENVIRONMENTAL REQUIREMENTS.
This information is incorporated by reference to Management's
Discussion and Analysis of Financial Condition and Results of
Operations of the 1999 Annual Report to Shareholders, pages 5-12,
which is Exhibit 13 hereto.
NUMBER OF EMPLOYEES.
There were 317 full-time employees and 4 part-time employees
at December 31, 1999.
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<PAGE>
ITEM 2 - PROPERTIES.
The Company has an agreement with KCP&L and EDE for joint
ownership of the coal-burning generating plant at Iatan,
Missouri. The Company's 18% share of this plant is 121 megawatts
(mw) of net capability. Refer to "Jointly Owned Iatan Plant"
incorporated by reference to Note 1 of Notes to Consolidated
Financial Statements in the 1999 Annual Report to Shareholders,
page 19, which is Exhibit 13 hereto.
The Company owns the Lake Road generating station in St.
Joseph, Missouri with an aggregate net capability of 257 mw
(summer rating), of which 107 mw is coal-fired and 150 mw utilize
natural gas and oil.
The Company owns a 62-mile segment of a 582 mile, 345 KV
transmission line connecting utilities from Kansas City, Missouri
to Minneapolis, Minnesota. A second 345 KV line, 23 miles in
length, is used as a tie-line for two neighboring utilities, one
of which pays all fixed and operating costs. The Company also
owns 32 miles of 345 KV line connecting the Iatan generating
plant with the Company's system. In addition, the Company
constructed, with six other regional utilities, a 103-mile, 345
KV transmission line, primarily in northwest Missouri, to
strengthen the interconnection network. The line provides a high
capacity interconnection facility directly linking the electric
transmission systems of Nebraska Public Power District,
Associated Electric Cooperative of Springfield, Missouri, and St.
Joseph Light & Power Company. The Company has 97 miles of 161 KV
transmission line which serves as the "backbone" for its internal
transmission/distribution system, and owns the necessary lower
voltage distribution lines, distribution substations,
transformers and equipment required to provide service in its
territory.
ITEM 3 - LEGAL PROCEEDINGS.
Certain legal actions are pending which, in management's
opinion, are not expected to materially affect the Company's
financial position or results of operations.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during
the fourth quarter of 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT.
The following are the executive officers of the Company:
T. F. STEINBECKER, President. Age 54. BSBA and MBA, University
of Missouri and CPA. Employed by the Company in 1975;
executive capacity since 1976; present position since May
1986.
G. L. MYERS, Vice President, General Counsel and Secretary. Age
46. AB, Washington University. JD, University of Missouri-
Kansas City. Employed by the Company and executive capacity
since 1979; General Counsel and Secretary from May 1989 -
January 1996; present position since February 1996.
L. J. STOLL, Vice President--Finance, Treasurer and Assistant
Secretary. Age 47. BSBA, Missouri Western State College.
MBA, Northwest Missouri State University. Employed by the
Company in 1975; executive capacity since 1980; present
position since May 1986.
J. A. STUART, Vice President--Customer Services and Energy
Delivery. Age 46. BSEE, California Polytechnic State
University. Employed by the Company in present position
since 1994.
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<PAGE>
D. V. SVUBA, Vice President--Energy Supply. Age 57. BSEE, Iowa
State University. MSEE, University of Missouri. Employed
by the Company in 1966; executive capacity since 1990;
present position since November 1990.
Each officer is covered by a three-year employment agreement.
There are no family relationships between any officers of the
Company.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
Information regarding the principal market for the Company's
common stock, the market prices and the dividends paid on such
stock for the past two years is incorporated by reference to the
1999 Annual Report to Shareholders, page 29, which is Exhibit 13
hereto.
There were 4,688 holders of record of the Company's common
stock as of February 3, 2000, the record date fixed for the
dividend paid on February 18, 2000.
ITEM 6 - SELECTED FINANCIAL DATA.
This information is incorporated by reference to the 1999
Annual Report to Shareholders, page 4, which is Exhibit 13
hereto.
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
This information is incorporated by reference to the 1999
Annual Report to Shareholders, pages 5-12, which is Exhibit 13
hereto.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
This information is incorporated by reference to the 1999
Annual Report to Shareholders, pages 13-27, which is Exhibit 13
hereto.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
PERSONS OF THE REGISTRANT.
Information required by Item 10 regarding directors is not
answered for the reason that the registrant will, within 120 days
after the close of the fiscal year, file with the Securities and
Exchange Commission a "Definitive Proxy Statement" pursuant to
Regulation 14A of the Securities Exchange Act of 1934. The
information required is incorporated by reference to such
Definitive Proxy Statement. Certain information
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<PAGE>
concerning the executive officers of the Company is set forth in
Part I under the caption "Executive Officers of the Registrant."
ITEM 11 - EXECUTIVE COMPENSATION.
Item 11 is not answered for the reason that the registrant
will, within 120 days after the close of the fiscal year, file
with the Securities and Exchange Commission a "Definitive Proxy
Statement" pursuant to Regulation 14A of the Securities Exchange
Act of 1934. The information required is incorporated by
reference to such Definitive Proxy Statement.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
Item 12 is not answered for the reason that the registrant
will, within 120 days after the close of the fiscal year, file
with the Securities and Exchange Commission a "Definitive Proxy
Statement" pursuant to Regulation 14A of the Securities Exchange
Act of 1934. The information required is incorporated by
reference to such Definitive Proxy Statement.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Item 13 is not answered for the reason that the registrant
will, within 120 days after the close of the fiscal year, file
with the Securities and Exchange Commission a "Definitive Proxy
Statement" pursuant to Regulation 14A of the Securities Exchange
Act of 1934. The information required is incorporated by
reference to such Definitive Proxy Statement.
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K.
Financial Statements:
This information is incorporated by reference (as set forth
below) to the 1999 Annual Report to Shareholders, which is
Exhibit 13 hereto.
Consolidated Statements of Income, page 13
Consolidated Balance Sheets, page 14
Consolidated Statements of Cash Flows, page 15
Consolidated Statements of Capitalization, pages 16-17
Consolidated Statements of Retained Earnings, page 17
Consolidated Statements of Taxes, page 18
Notes to Consolidated Financial Statements, pages 19-26
Responsibility for Financial Statements, page 27
Report of Independent Public Accountants, page 27
FINANCIAL STATEMENT SCHEDULES:
Schedule II-Valuation and Qualifying Accounts - For the years
ended December 31, 1999, 1998 and 1997 (page 11).
Schedules not listed above are omitted because of absence of
conditions under which they are required or because the required
information is included in the financial statements submitted.
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<PAGE>
LIST OF EXHIBITS:
Exhibit 2 -Agreement and Plan of Merger dated March 4,
1999 between UtiliCorp United Inc. and St. Joseph
Light & Power Company, which is incorporated by
reference to Exhibit 2 in File No. 333-77703 filed
by UtiliCorp United Inc.
Exhibit 3 (a) - Restated Articles of Incorporation adopted
on May 20, 1987, which are incorporated by
reference to page 16 of the 1987 Form 10-K.
(b) - By-laws of Company as amended on March
19, 1997, which are incorporated by reference to
Exhibit 3 (b) to the 1997 Form 10-K.
Exhibit 4 (a) - Indenture of Mortgage and Deed of Trust
dated April 1, 1946, between the Company and
Harris Trust and Savings Bank and Bartlett Boder,
Trustee which is incorporated by reference to
Exhibit (b) (1)-C in File No. 2-62825.
(b) - Seventeenth Supplemental Indenture
dated as of February 1, 1991 between the Company
and Harris Trust and Savings Bank, which is
incorporated by reference to the 1995 Form 10-K.
(c)- Medium-Term Notes Issuing and Paying Agency
Agreement dated as of November 19, 1993 between
the Company and Harris Trust and Savings Bank,
which is incorporated by reference to the 1995
Form 10-K.
(d) - Rights Agreement dated September 18,
1996, which is incorporated by reference to
Exhibit 4 to Form 8-K, dated October 1, 1996.
Amendment to the Rights Agreement as amended on
March 4, 1999, which is incorporated by reference
to Exhibit 4.1 to Form 8-K, dated March 4, 1999.
Long-term debt instruments of the Company in
amounts not exceeding ten percent of the total
assets of the Company will be furnished to the
Commission upon request.
Exhibit 10(a) -Coal Freight Agreement between Burlington
Northern Railroad Company, Seller, and Kansas City
Power & Light Company, St. Joseph Light & Power
Company and The Empire District Electric Company,
Buyers. This exhibit is incorporated by reference
to page 17 of the 1986 Form 10-K. Amendment to
Coal Freight Agreement, as amended on May 20,
1995, is incorporated by reference to the 1995
Form 10-K.
(b) -Coal Supply Agreement between Atlantic
Richfield Company, Seller, and Kansas City Power &
Light Company, St. Joseph Light & Power Company
and The Empire District Electric Company, Buyers.
This exhibit is incorporated by reference to page
17 of the 1983 Form 10-K.
(c) -CFSI Agreement which is incorporated by
reference to page 17 of the 1989 Form 10-K.
(d) - ** Form of Key Management Employment
Agreements which is incorporated by reference to
page 18 of the 1990 Form 10-K. Amendment to Key
Management Employment Agreements dated December 1,
1993, which is incorporated by reference to page
18 of the 1993 Form 10-K. Form of Amendment to
Amended and Restated Employment Contract dated
March 20, 1996 and Form of Amendment to Amended and
Restated Employment Agreement dated January 7,
1999, which are incorporated by reference to
Exhibit 10(d) to the 1998 Form 10-K.
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<PAGE>
(e) -Directors Indemnification Agreement,
which is incorporated by reference to page 19 of
the 1993 Form 10-K.
(f) -** Supplemental Executive Retirement
Plan which is incorporated by reference to page 19
of the 1990 Form 10-K. Amendment to Supplemental
Executive Retirement Plan as amended on November
17, 1993, which is incorporated by reference to
page 20 of the 1993 Form 10-K. Amendment to
Supplemental Executive Retirement Plan as amended
and restated January 1, 1999, which is incorporated
by reference to Exhibit 10(f) to the 1998 Form 10-K.
(g) -Gas Service Agreements with ANR Pipeline
Company, which are incorporated by reference to
page 21 of the 1993 Form 10-K.
(h) -** 1998 Long-Term Incentive Plan which
is incorporated by reference to the May 20, 1998
Proxy Statement. Officers' Long-Term Incentive
Plan dated January 1, 1999, which is incorporated
by referene to Exhibit 10(h) to the 1998 Form 10-K.
(i) -Purchased power agreement with Nebraska
Public Power District, which is incorporated by
reference to Exhibit 10(j) to the 1996 Form 10-K.
(j) - ** Officers' Annual Bonus Plan, which is
incorporated by reference to Exhibit 10(k) to the
1997 Form 10-K.
(k) -** SJLP Inc. Officers' Incentive Plan,
which is incorporated by reference to Exhibit
10(k) to the 1998 Form 10-K.
Exhibit 13 -* The 1999 Annual Report to Shareholders.
Exhibit 21 -Subsidiaries of Registrant, which is
incorporated by reference to Exhibit 21 to the
1997 Form 10-K.
Exhibit 23 -* Consent of Independent Public Accountants.
Exhibit 27 -* Financial Data Schedule.
_________________________________
* Filed herewith.
** Exhibits marked with a double asterisk relate
to management contracts or compensatory arrangements.
REPORTS ON FORM 8-K:
No Current Report on Form 8-K was filed during the quarter ended
December 31, 1999.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To St. Joseph Light & Power Company:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements included in St.
Joseph Light & Power Company's Annual Report to Shareholders
incorporated by reference in this Form 10-K, and have issued our
report thereon dated January 21, 2000. Our audits were made for
the purpose of forming an opinion on those statements taken as a
whole. The schedule listed in the index above is presented for
purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial
statements. This schedule has been subjected to the auditing
procedures applied in our audits of the basic financial
statements and, in our opinion, fairly states in all material
respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 21, 2000
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
ST. JOSEPH LIGHT & POWER COMPANY
(Registrant)
March 15, 2000 By /s/ T.F. Steinbecker
T.F. Steinbecker,
President
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
/s/ T.F. Steinbecker President & Director March 15, 2000
T.F. Steinbecker (Chief Executive Officer)
/s/ L.J. Stoll Vice President-Finance, March 15, 2000
L.J. Stoll Treasurer & Assistant
Secretary (Principal
Financial & Accounting
Officer)
/s/ J.P. Barclay, Jr. Director March 15, 2000
J.P. Barclay, Jr.
/s/ D.A. Beck Director March 15, 2000
D.A. Beck
/s/ D.A. Burkhardt Director March 15, 2000
D.A. Burkhardt
/s/ J.P. Carolus Director March 15, 2000
J.P. Carolus
/s/ W.J. Gremp Director March 15, 2000
W.J. Gremp
/s/ D.W. Shinneman Director March 15, 2000
D.W. Shinneman
/s/ R.L. Simpson Director March 15, 2000
R.L. Simpson
/s/ G.R. Sprong Director March 15, 2000
G.R. Sprong
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ST. JOSEPH LIGHT & POWER CO.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
COLUMN A COLUMN B COLUMN C COLUMN D
COLUMN E
Deductions
for Purposes
Balance Additions for Which
Balance
Beginning Charged Charged to Reserves
at End
Description of Year to Expense Construction Were Created
of Year
<S> <C> <C> <C> <C>
<C>
Valuation accounts deducted
from assets to which they
apply-
Accumulated Provision for
Uncollectible Accounts:
December 31, 1999 $ 281,592$ 223,600 $ - $ 194,813(1) $ 310,379
December 31, 1998 $ 270,028$ 272,450 $ - $ 260,886(2) $ 281,592
December 31, 1997 $ 232,018$ 218,224 $ - $ 180,214(3) $ 270,028
Other reserves-
Accumulated Provision for
Injuries and Damages:
December 31, 1999 $ 464,808$ 19,027 $ 5,402 $ 214,297 $ 274,940
December 31, 1998 $ 357,030$ 181,933 $ 5,274 $ 79,429 $ 464,808
December 31, 1997 $ 392,547$ 81,304 $ 14,219 $ 131,040 $ 357,030
Accumulated Provision for
Major Medical:
December 31, 1999 $ 105,525$1,300,151 $ 339,384 $1,639,535 $ 105,525
December 31, 1998 $ 105,525$1,131,796 $ 299,227 $1,431,023 $ 105,525
December 31, 1997 $ 5,525$ 1,262,902 $ 297,971 $1,460,873 $ 105,525
Accumulated Provision for
Other Post Employment
Benefits:
December 31, 1999 $1,298,544$ 962,381 $ 251,214 $1,274,787 $1,237,352(4)
December 31, 1998 $1,343,394$ 946,844 $ 231,725 $1,223,419 $1,298,544(5)
December 31, 1997 $1,356,468$ 996,974 $ 198,567 $1,208,615 $1,343,394(6)
(1) Net of $146,413 recovery on accounts previously charged off.
(2) Net of $149,349 recovery on accounts previously charged off.
(3) Net of $204,682 recovery on accounts previously charged off and $75,000
reserve of Percy Kent Bag Co., Inc. on acquisition date.
(4) Includes Iatan reserve of $139,191.
(5) Includes Iatan reserve of $153,001.
(6) Includes Iatan reserve of $172,272.
</TABLE>
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<PAGE>
ST. JOSEPH
LIGHT & POWER
COMPANY
<PAGE>
As an investor-owned utility, St. Joseph Light & Power Company serves more than
3,300 square miles in all or part of 10 northwest Missouri counties.
Light & Power provides electric energy to nearly 63,000 customers in 74 cities,
towns and villages, and in a large rural area. The home office is in St. Joseph,
a city of about 73,000, which represents about one-half the population of the
service territory. Electric retail revenues represented about 72 percent of the
company's 1999 revenues.
The company supplies natural gas to almost 6,400 natural gas customers in
Maryville, a state university town of about 10,000 and 14 other communities.
Light & Power does not provide natural gas to St. Joseph. The company also
supplies industrial steam to six customers in St. Joseph.
Light & Power also owns SJLP Inc., a non-regulated investment subsidiary.
St. Joseph Light & Power Company has been in the public utility business since
1883. It became an independent, investor-owned business in 1950. St. Joseph
Light & Power has more than 4,700 shareholders, representing all 50 states. The
company's stock is traded on the New York Stock Exchange under the symbol SAJ.
PROCEDURE FOR EXCHANGE OF COMMON STOCK
- --------------------------------------------------------------------------------
As soon as practicable after the closing of the merger, an Exchange Agent
will mail a letter of transmittal to each holder of record of shares of Light
& Power common stock. That letter will contain instructions to be followed by
the shareowner in surrendering his/her Light & Power certificates in exchange
for certificates of UtiliCorp common stock.
Once the Exchange Agent has received the Light & Power certificates and the
transmittal letter, signed by the shareowner, the Exchange Agent will forward
the certificates representing the whole number of shares of UtiliCorp stock
to which the former Light & Power shareowner is entitled. The certificates
will be registered in such names as the owner may request. The Light & Power
shareowner will also receive a check representing the cash value of
fractional shares of UtiliCorp stock. That cash payment will be subject to
income tax withholding, as appropriate.
- --------------------------------------------------------------------------------
1
<PAGE>
PRESIDENT'S MESSAGE
FELLOW SHAREOWNER:
1999 was a significant year in the long and successful history of St. Joseph
Light & Power Company. On March 5, the company announced the signing of a
definitive agreement to merge our company with UtiliCorp United Inc., of Kansas
City, Missouri.
Upon completion of the merger, you will receive $23 worth of UtiliCorp common
stock for each share of Light & Power Company stock, on a tax-free basis. In
addition, you will benefit from increased liquidity, enhanced opportunities for
long-term growth and, we expect, improvement in the dividend.
During this past year, your management team has focused on working to complete
the merger on a timely basis, as well as maintaining the record of excellent
service provided our customers and sustaining a competitive return to our
shareowners.
1999 Operating Results
A combination of factors adversely impacted the financial results of the company
during 1999. As a result, diluted earnings per share for the year were $.74,
compared with $1.31 per share reported in 1998. Net income in 1999 totaled $6.1
million, down from the $10.7 million reported in 1998.
The primary factors impacting the company's financial results were flat electric
retail revenues, increased per-unit costs for purchased power and merger-related
expenses. Excluding the merger-related expenses, 1999 earnings would have
totaled $1.07 per common share.
Please refer to Management's Discussion and Analysis, beginning on Page 5, for a
discussion of 1999 operating results.
RETURN TO SHAREOWNERS
Total return to shareowners (dividends plus stock price appreciation) in 1999
was 19.96 percent, placing the company eighth in the Edison Electric Institute
100 Index of Investor-Owned Electrics.
In January 2000, the board of directors approved a regular quarterly dividend of
25 cents per common share. This dividend continues Light & Power's record of
paying a dividend each quarter since the company became independent in 1950. The
effective annual rate is $1.00 per share.
RATE PROCEEDINGS
In July, the Missouri PSC concluded the rate proceedings begun in 1998. The
proceedings involved requests by Light & Power for increases in electric,
natural gas and industrial steam revenues and a commission staff complaint
alleging that electric revenues should be reduced. The electric filings by the
company and the PSC staff were consolidated.
The parties to the cases reached stipulated agreements, which the PSC approved,
that called for the company to implement certain accounting changes and to
reduce annual electric and industrial steam revenues by $2.5 million and
$25,000, respectively, for service provided after October 30, 1999. There were
no changes in natural gas prices. The accounting changes and revenue reductions
required by the agreements had a negligible effect on 1999 and are expected to
reduce net income about $300,000 annually.
RESTRUCTURING IN MISSOURI
While Missouri has yet to take any action on deregulating the electric industry,
activity has increased in the current session of the General Assembly. Industry
representatives have been meeting with various stakeholders since late summer
1999 on the issue. Consensus seems to be coalescing around a strategy that would
have the legislature first deal with the tax issues associated with
restructuring the industry and then pass a deregulation bill.
Failure to make changes in the way utilities are taxed could result in lower
taxes for competitors not currently regulated by the PSC. Both the tax bills and
some of the discussion
2
<PAGE>
PRESIDENT'S MESSAGE
drafts of deregulation legislation currently being considered contain a
provision that deregulation cannot become effective until tax reforms have been
approved.
ENVIRONMENT
The quality of life in northwest Missouri is a special concern and the company
endeavors to serve as an example of environmental responsibility.
Our efforts to protect that quality of life were again recognized by the
National Arbor Day Foundation. For the third consecutive year, Light & Power was
named a Tree Line USA utility. The award acknowledges Light & Power's efforts to
promote and protect healthy trees while ensuring reliable service for customers.
In 1999, the company invested about $1.2 million for projects at the Lake Road
plant necessary to comply with the requirements of the Clean Air Act. Most of
those projects related to modifications to the plant's coal-handling facilities.
In total, about $18 million will be invested to achieve compliance.
YEAR 2000 ACTIVITIES
As expected, the midnight arrival of the Year 2000 was a non-event for our
customers from a service standpoint. While we were confident of the outcome,
many employees were on duty to handle any unforeseen emergency. When the hour
arrived, every system functioned as expected and no service interruptions or
other system failures occurred.
I am extremely proud of the employees in the Information Systems Department and
all the other employees involved in this complex endeavor. The years of
planning, implementing and testing paid off.
MERGER UPDATE
As you know, the merger was approved at the special shareowners' meeting in
June. Management and the Board of Directors are committed to securing regulatory
approval of the merger and implementing a smooth transition of Light & Power's
operations into UtiliCorp.
In October 1999, Light & Power and UtiliCorp filed a joint application with the
PSC for approval of the merger. As part of the application, the companies filed
a proposed procedural schedule outlining dates for significant events in the
approval process.
In late December, the PSC issued an order that essentially accepted the schedule
proposed by the companies, which calls for the hearing in mid-July. In addition,
in an order issued in January 2000, the PSC denied a motion by the PSC staff,
the Office of Public Counsel and intervenors to consolidate our merger
proceeding with that of UtiliCorp and The Empire District Electric Company of
Joplin, Missouri. Approval of that motion could have delayed the completion of
our merger.
All other required state regulatory commission approvals have been received.
In late November, an application was filed requesting the Federal Energy
Regulatory Commission's approval of UtiliCorp's mergers with Light & Power and
Empire District. The filing requested an expedited review of the application and
a decision is expected by mid-2000.
Although there are no statutory time limits for regulatory actions, we expect
the timing of the various regulatory decisions to allow for the closing of the
merger in the fall of 2000.
RECOGNITION OF EMPLOYEES
I want to conclude by recognizing the dedication of our employees, past and
present. It has been their hard work and commitment to customer service that has
made St. Joseph Light & Power Company a successful company.
/s/Terry F. Steinbecker
Terry F. Steinbecker
President and Chief Executive Officer
March 13, 2000
3
<PAGE>
SELECTED FINANCIAL INFORMATION
The following table sets forth financial data regarding St. Joseph Light &Power
Company's financial position and operating results. This information should be
read in conjunction with Management's Discussion and Analysis and the
Consolidated Financial Statements and Notes thereto, appearing elsewhere in this
Annual Report.
<TABLE>
<CAPTION>
(In Thousands Except Per Share Data and Percentages)
1999 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
STATEMENTS OF INCOME:
Operating revenues $ 120,949 $ 124,374 $ 116,165 $ 95,869 $ 93,521 $ 90,782
Operating expenses 104,391 102,187 93,177 74,941 73,249 70,033
--------- --------- --------- --------- --------- ---------
Operating income 16,558 22,187 22,988 20,928 20,272 20,749
Interest charges, net 7,312 6,787 6,480 5,807 5,555 4,460
Other income (507) (847) (440) (504) (1,470) (32)
Income taxes 3,705 5,512 6,214 5,268 5,147 5,255
Minority interest (79) 71 (106) -- -- --
--------- --------- --------- --------- --------- ---------
Net income $ 6,127 $ 10,664 $ 10,840 $ 10,357 $ 11,040 $ 11,066
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
COMMON STOCK DATA:
(adjusted to reflect two-for-one stock split in July 1996)
For the year ended December 31--
Weighted average shares outstanding 8,212 8,100 7,989 7,868 7,813 7,884
Basic earnings per share $ .75 $ 1.32 $ 1.36 $ 1.32 $ 1.41 $ 1.40
Diluted earnings per share $ .74 $ 1.31 $ 1.36 $ 1.32 $ 1.41 $ 1.40
Dividends per common share $ 1.00 $ .98 $ .96 $ .94 $ .92 $ .90
Return on average common equity 6.4% 11.4% 12.2% 12.4% 13.9% 14.4%
As of December 31--
Market price per common share $ 20.50 $ 17.94 $ 17.75 $ 15.38 $ 17.75 $ 14.25
Book value per common share $ 11.63 $ 11.76 $ 11.34 $ 10.87 $ 10.42 $ 9.93
Liquidity and capital resources data:
Capital --
Expenditures, excluding AFUDC $ 12,953 $ 16,442 $ 14,346 $ 14,318 $ 21,781 $ 12,224
Percent of expenditures financed
internally from operations 22% 79% 79% 92% 58% 77%
AFUDC as a percent of net income 3% 4% 2% 5% 4% 2%
Capitalization ratios
Common equity 58% 57% 57% 54% 53% 59%
Long-term debt (excluding 42% 43% 43% 46% 47% 41%
current maturities)
Ratio of earnings to fixed charges 2.27 3.23 3.47 3.44 3.63 4.39
Total assets $ 261,326 $ 251,255 $ 243,769 $ 227,250 $ 219,330 $ 199,699
Long-term obligations $ 71,294 $ 76,417 $ 71,837 $ 76,371 $ 75,612 $ 55,627
</TABLE>
4
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
GENERAL
In Management's Discussion and Analysis, we explain the general financial
condition and operating results of St. Joseph Light & Power Company, a public
utility, its wholly owned subsidiary, SJLP Inc. and its subsidiary, Percy Kent
Bag Co., Inc. (Percy Kent). As you read Management's Discussion and Analysis, it
may be helpful to refer to our Consolidated Statements of Income, which present
the results of operations for 1999, 1998 and 1997.
We are engaged primarily in the generation and distribution of electric energy,
serving approximately 63,000 customers in northwest Missouri. We also sell
natural gas in 15 communities in the northern part of our service area and
industrial steam to six customers in St. Joseph. SJLP Inc. was formed in
September 1996 to pursue investments in non-utility areas. Effective May 31,
1997, SJLP Inc. acquired a controlling interest in Percy Kent, a manufacturer of
multiwall and small paper bags, primarily for food products, agricultural
products, specialty chemicals, pet foods and other consumer packaging companies
throughout the United States. Neither SJLP Inc.'s nor Percy Kent's operations
were material to St. Joseph Light & Power Company's consolidated financial
position or results of operations in any of the periods presented.
PROPOSED MERGER -- On March 4, 1999, we entered into an Agreement and Plan of
Merger to form a strategic business combination with UtiliCorp United Inc. Under
terms of the Agreement, each share of our common stock, valued at $23.00 per
share, will be exchanged for UtiliCorp United Inc. common stock. The Agreement
was approved by a vote of our shareholders at a special meeting in 1999, and by
the Public Utility Commissions of Colorado, West Virginia, Iowa, and Minnesota.
The transaction is subject to several additional closing conditions, including
approval by the Federal Energy Regulatory Commission (FERC), the Department of
Justice, the Federal Communications Commission, and the Missouri Public Service
Commission (PSC). The PSC has scheduled hearings for mid-July 2000. We expect
the merger to be completed in the fall of 2000.
After tax merger expenses of $2.7 million were incurred during 1999. Additional
merger-related expenses are expected to be incurred in 2000, resulting in an
after tax impact to earnings of approximately $4.5 million.
RESULTS OF OPERATIONS
1999 VS. 1998
EARNINGS -- Diluted earnings per share totaled $.74 in 1999, compared with 1998
earnings of $1.31 per share. The earnings decrease was primarily the result of
flat electric retail revenues, increases in per unit purchased power costs, and
expenses relating to the proposed merger.
ELECTRIC REVENUES -- 1999 electric operating revenues were $90.5 million, an
increase of 1% from 1998. The slight growth in 1999 revenues was primarily due
to increased sales for resale. Participation in an exchange agreement with
another utility, which began in 1998 (see 1998 vs. 1997 "Electric Revenues"),
increased the amount of energy available for resale in 1999, resulting in a 111%
increase in sales for resale volumes.
Retail sales totaled 1.67 million megawatt hours (mwh) in 1999, a 2% increase
from the 1.64 million mwh reported in 1998. The continued strong economy boosted
retail sales to the commercial (1.4%) and industrial (6.2%) customer classes.
Milder than normal temperatures resulted in a decline of 1.7% in sales to
residential customers. Although retail sales increased, this change in sales mix
resulted in flat retail revenue.
Electric retail revenues were also reduced by approximately $350,000 due to the
rate reductions implemented October 31, 1999 (see "Effects of Regulation").
5
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OTHER UTILITY -- Industrial steam revenues increased 5% from 1998's level. Sales
in 1999 increased 7% as a result of increased sales to a major customer.
Gas revenues declined 7% from 1998 as the result of lower per unit gas prices,
which are passed on to retail customers, and changes in the mix of sales to the
various customer classes due to milder weather.
MANUFACTURING REVENUES -- The operations of Percy Kent are reflected in
manufacturing revenues and cost of goods sold, which both decreased 18%. The
decreases are primarily due to reduced demand and the loss of two major
customers.
FUEL AND PURCHASED POWER -- Total energy costs (fuel and purchased power for
system energy and resale) were $34 million for 1999, $4 million more than the
1998 expense. This increase was the result of higher per unit costs for
purchased power and increased system requirements.
Per unit fuel costs were slightly higher in 1999 at $1.114 per million British
thermal units (Btu), up from $1.099 per million Btu in 1998, due to changes in
the mix of fuels and generating units utilized. Similar to the pattern of recent
years, coal made up 90% of the total fuel burned in 1999. The cost of coal
burned decreased from $.979 per million Btu in 1998 to $.928 per million Btu in
1999.
The coal-fired Iatan plant provided approximately 48% of our overall energy
needs in 1999, a decrease from 50% in 1998, due to unscheduled outages. A
Wyoming mine supplies low-sulfur coal to the plant under a 20-year contract,
which expires in 2003. The contract was renegotiated in 1999. In return for
lower unit prices through the remaining contract term, we made a prepayment of
$3.4 million. This prepayment is being amortized over the coal deliveries under
the contract and is included in Regulatory Assets on our balance sheet. The coal
is delivered by rail under an agreement that extends through 2000.
The Lake Road units supplied 26% of our energy needs, up slightly from 25% in
1998. Per unit fuel costs at Lake Road were up 3% in 1999.
We met the remaining 26% of our energy needs in 1999 through purchased power
arrangements compared to 25% in 1998. Both years reflect the purchase of
replacement power for Iatan outages. Purchased power fixed charges for firm and
peaking capacity were $3.3 million for 1999 and $2.7 million for 1998. We expect
our use of purchased power to increase in 2000 due to a planned maintenance
outage for the Iatan plant. We have contracted to purchase 171,600 mwh of energy
during a period beginning in March and extending through May of 2000.
Per unit costs of purchased power increased almost 6% in 1999. Along with many
other utilities, we saw a significant increase in these costs during the summer
months due to high summer demands and constraints on the regional transmission
system. We expect this trend of higher prices for purchased energy to continue.
OTHER OPERATIONS -- Other operations expenses for 1999 decreased $1.6 million in
comparison to 1998. The decrease is primarily the result of decreased payroll
and benefit costs for the year in addition to lower Year 2000 expenses. The
pension credit was $3.0 million and $2.2 million in 1999 and 1998, respectively.
See Note 2, Benefit Plans, in the footnotes.
MAINTENANCE -- Consistent with prior years, maintenance expenses remained
relatively stable in 1999, decreasing by $160,000 from 1998 levels, due to lower
maintenance costs at the Lake Road facility. The balanced expenses continue to
reflect our efforts to schedule maintenance outages in a way which minimizes
both maintenance and generation replacement costs.
INTEREST CHARGES -- The increase in interest charges is primarily due to an
increase in short-term notes payable throughout the year, partially offset by
reduced interest charges related to long-term debt. The increase in short-
6
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
term debt is a result of lower cash flows from operating activities, caused
primarily by merger-related expenses, and investments in our non-utility
businesses.
1998 VS. 1997
EARNINGS -- Diluted earnings per share totaled $1.31 in 1998, compared with 1997
earnings of $1.36 per share. The earnings decrease was primarily the result of
increases in per unit purchased power costs.
ELECTRIC REVENUES -- 1998 electric operating revenues were $89.7 million, an
increase of 3% from 1997. The growth in 1998 revenues was primarily due to
increased retail sales.
Retail sales totaled 1.64 million mwh in 1998, a 4% increase from the 1.58
million mwh reported in 1997. Warmer summer weather and the continued strong
economy boosted retail sales to all three customer classes -- residential, 2.1%;
commercial, 4.7%; and industrial, 5.8%.
We entered into an agreement with another utility in which we agreed to transfer
energy to them in 1998 in exchange for receiving approximately the same amount
of energy from them in 1999. Participation in this agreement reduced the amount
of energy available for resale in 1998, resulting in a 42% decrease in sales for
resale volumes.
OTHER UTILITY -- Industrial steam revenues increased 1.5% from 1997's level.
Sales in 1998 increased 3% as a result of increased sales to a major customer.
Gas revenues declined 20% from 1997, as the result of a 14% decrease in retail
sales and transportation services due to reduced heating requirements and lower
per unit gas prices which are passed on to customers.
MANUFACTURING REVENUES -- Manufacturing revenues and cost of goods sold
increased 38% and 34%, respectively. The increases are due to the inclusion of a
full year of operating results of Percy Kent in 1998 as compared to only seven
months in 1997, partially offset by the elimination of lower margin contracts.
FUEL AND PURCHASED POWER -- Total energy costs were $30 million for 1998, $2
million more than the 1997 expense. This increase was the result of higher per
unit costs for purchased power, increased system requirements, and more
expensive replacement energy required by outages at the Iatan generating
station, partially offset by lower resale requirements.
Per unit fuel costs were slightly higher in 1998 at $1.099 per million Btu, up
from $1.097 per million Btu in 1997, due to changes in the mix of fuels and
generating units utilized. Of the total fuel burned in 1998, 92% was coal,
similar to the pattern of recent years. The cost of coal burned decreased from
$1.002 per million Btu in 1997 to $.979 per million Btu in 1998.
The coal-fired Iatan plant provided approximately 50% of our overall energy
needs in 1998, a decrease from 52% in 1997, due to unscheduled outages. The Lake
Road units supplied 25% of our energy needs, down slightly from 26% in 1997. Per
unit fuel costs at Lake Road were up less than 1% in 1998 from 1997.
We met 25% of our energy needs through purchased power arrangements in 1998
compared to 22% in 1997, reflecting the purchase of replacement power for Iatan
outages. Purchased power fixed charges for firm and peaking capacity were $2.7
million for 1998 and $2.4 million for 1997.
Per unit costs of purchased power increased almost 18% in 1998. Along with many
utilities in the midwest, we saw the per unit costs for purchased power reach
unprecedented levels during one week in June 1998. The situation was a result of
hot, humid weather and reduced availability of transmission and generation
facilities, placing the region's electric supply under stress.
OTHER OPERATIONS -- Other operations expenses for 1998 increased $1.3 million in
comparison to 1997. The increase is primarily the result of the inclusion of a
full year of Percy Kent's expenses and increased Year 2000 expenses, partially
offset by lower benefits costs for the year.
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
MAINTENANCE -- Consistent with prior years, maintenance expenses remained
relatively stable in 1998, increasing only $.5 million over 1997, due to
increased Lake Road maintenance costs.
INTEREST CHARGES -- The increase in interest charges is primarily due to the
inclusion of a full year of Percy Kent's expenses.
FUTURE OUTLOOK
LIQUIDITY AND CAPITAL RESOURCES -- Our total authorized capital stock includes
25 million shares of common stock, four million shares of cumulative preferred
stock, and two million shares of preference stock. Common equity was 58% of
total capitalization in 1999 and 57% in 1998 and 1997.
Financial coverages are at levels in excess of those required for the issuance
of debt and preferred stock. St. Joseph Light & Power Company currently holds a
secured debt rating of A and an unsecured debt rating of A- from Standard &
Poors; we were placed on "Credit Watch-Negative" as a result of the proposed
merger. At year-end, we had $354,000 in cash and temporary investments.
Our short-term financing requirements are satisfied through borrowings under
unsecured lines of credit maintained with banks. At December 31, 1999, we had
available committed lines of credit of $3.0 million and an additional $6.7
million of uncommitted lines.
Percy Kent also has a revolving loan agreement through a finance company which
provides them with up to $4.5 million of available credit. At December 31, 1999,
the outstanding borrowings under this loan agreement, in the amount of $2.9
million, were classified as current maturities of long-term debt in our balance
sheet.
Cash generated from operations was lower in 1999, but remains strong. Over the
last three years, operating cash flows have been $10.2 million, $20.6 million,
and $18.6 million, respectively. Our ratio of earnings to fixed charges was 2.27
for 1999.
We project capital expenditures (excluding allowance for funds used during
construction (AFUDC) and including non-utility investments) for the five-year
period ending in 2004 to be approximately $62.1 million. We expect to finance
these expenditures primarily through internally generated funds supplemented by
external financing as necessary.
The combined aggregate amount of maturities and payments for long-term
obligations and for operating leases for the next five years is $10.9 million.
See Note (b), Long-Term Debt, in our statements of capitalization and Note 7,
Commitments and Contingencies, in the footnotes.
IMPACT OF ACCOUNTING STANDARDS CHANGES -- There were no accounting changes in
1999, 1998 or 1997 that had a material impact on the financial statements. See
"Effects of Regulation" for a discussion regarding the accounting changes
implemented pursuant to the PSC Order issued in 1999.
MARKET RISK -- We are exposed to various market risks in our business
operations. Commodity market prices are one such risk as Missouri does not have
an energy cost adjustment provision to allow for current recovery of changes in
the cost of fuel or purchased power.
We have entered into a long-term, fixed-price contract to meet our fuel needs at
the coal-fired Iatan generating plant to mitigate our exposure to market price
fluctuations. Coal for the Lake Road plant, approximately $8.3 million in 1999,
is mainly purchased on the spot market. The availability and cost of rail
transportation used to deliver coal to our generating facilities are additional
market risks we face. Again, we have rail service contracts for both Iatan and
Lake Road to help reduce our risk.
We are also exposed to price risk when we purchase energy to meet our system
requirements throughout the year. We have been able to partially reduce our
exposure to that risk for approximately 75 percent of our anticipated 2000
energy purchases by entering into cost-based contracts.
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
Changes in spot market prices for energy, similar to those experienced the last
two summers, can have a significant negative impact on our results (see "Fuel
and Purchased Power"). We also have the ability to reduce our need for spot
market purchases by placing into service higher cost generating units when
market prices exceed the cost of the units' operation. We are required to
maintain certain levels of capacity for which long-term, fixed price contracts
are in place (see "Capacity").
Commodity market prices for natural gas also represent a risk. However, changes
in the price of natural gas purchased for resale are passed on to our customers.
Interest and inflation rates also pose risks to our financial position. We have
limited our exposure to interest rate risk by maintaining the majority of our
debt capitalization in long-term, fixed-rate instruments. During the year, we
had weighted average short-term debt outstanding, subject to variable market
rates, of $15,531,000.
Under the ratemaking practices followed by the PSC, only historical costs are
recoverable in revenues. Assuming adequate and timely rate relief, we will
recover the increases in cost of service caused by inflation.
About two-thirds of our approximately 320 employees are covered under physical
and clerical bargaining agreements that expire July 31, 2001. Substantially all
of Percy Kent's manufacturing labor force is covered by a collective bargaining
agreement, which expires in March 2003.
COMPETITION/DEREGULATION -- While state law currently prohibits competing with
rural electric cooperatives for existing customers, competition remains for new
customers, especially industrial, in the rural areas of our service territory.
In order to compete for new, large customers and encourage businesses to locate
in our service territory, we offer an economic development incentive rate for
customers meeting certain criteria.
The 1992 Energy Policy Act (the Act) promotes competition in the way electricity
is transmitted and marketed. The Act provides for increased competition in the
wholesale electric market by permitting the FERC to order third party access to
utilities' transmission systems and by liberalizing the rules of generating
facility ownership. The FERC's Order 888 requires all transmission owning public
utilities in the country to provide non-discriminatory transmission service to
all eligible customers using FERC's standard ProForma Open Access Transmission
Tariff. As an eligible customer under FERC's tariff, we are able to access
utilities, marketers, and wholesale generators throughout the country for the
purchase and sale of wholesale electric energy. We also use the regional
transmission tariffs of the MidContinent Area Power Pool (MAPP) and Southwest
Power Pool which are rates less than those available under FERC's ProForma
tariff.
The opening of the nation's transmission system has increased the size of the
market from which we buy and sell wholesale energy. We believe that increased
transmission access will continue to increase the demand for available wholesale
energy supply and result in higher purchased energy costs.
In December 1999, the FERC issued Order No. 2000 which calls for all
transmission owners to join regional transmission organizations (RTOs). The
formation of these umbrella organizations will put all public utility
transmission facilities within a region under common control. The FERC believes
RTOs will increase competition between electric service providers.
The rule requires all public utilities that own, operate, or control interstate
transmission to file, by October 15, 2000, proposals to participate in an RTO,
or an explanation of why they have not acted, or reasons why they cannot join an
RTO. The FERC expects all utilities to be members of operating RTOs by December
15, 2001. We are currently reviewing our options for participation in an RTO
that would meet the FERC's requirements.
In March 1997, the PSC opened a docket to investigate restructuring in the
electric utility industry in the state. The Retail Electric Competition Task
Force, comprised of representatives from various groups, was charged with
preparing comprehensive reports for the PSC. The reports were prepared in 1998
based upon a thorough investigation of retail wheeling of electricity and
related issues. Included were recommendations outlining how Missouri should
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
implement retail electric competition should enabling legislation be enacted.
At the present time, a general consensus exists that the legislature should
first deal with the tax issues associated with restructuring the industry and
then pass a deregulation bill. Since a provision in the Missouri constitution
requires voter approval of new taxes, the various tax issues cannot be addressed
in a deregulation law as has been done in many other states. Failure to make
changes in the way utilities are taxed could result in lower taxes for
competitors not currently regulated by the PSC. We expect that a proposal to
reform utility taxes will be submitted to voters as a constitutional amendment
in November 2000. If voters approve the proposal, a deregulation law could be
passed in the 2001 session. Based on current legislative activity, we believe
that retail competition might begin in Missouri sometime during 2004.
Based on the PSC docket and deregulation plans implemented or considered by
other states, we believe it is most likely that the generation portion of the
business could become unregulated while the transmission and distribution
functions will continue to be regulated.
If retail wheeling were to be implemented, we believe that our current low
prices and the excellent power supply options available to us to meet future
requirements will permit us to remain competitive in comparison with other
regional suppliers.
EFFECTS OF REGULATION -- We are subject to rate regulation by the PSC. Rates are
established to allow us an opportunity to recover our costs and earn a return on
our investment. We currently apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," which
recognizes the economic effects of rate regulation. In the event we determine
that we no longer meet the criteria for following SFAS 71, the accounting impact
would be a non-cash charge to operations of an amount that could be material.
Criteria that give rise to the discontinuance of SFAS 71 include (1) increasing
competition that restricts our ability to establish prices to recover specific
costs, and (2) a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. We
continually review the applicability of SFAS 71 considering the current
regulatory environment.
Based on our current evaluation of the various factors and conditions that are
expected to impact future cost recovery (see "Competition/Deregulation"), we
believe that our regulatory assets, including those related to generation, are
probable of future recovery and that the utilization of SFAS 71 continues to be
appropriate.
If the generation portion of the business is deregulated, all or a portion of
its net regulatory assets, which are approximately $4.6 million at December 31,
1999, are expected to be recovered from ratepayers through a charge collected by
the regulated businesses.
10
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
On December 1, 1998, we filed rate cases before the PSC asking for price
increases of approximately $6,100,000, $500,000, and $275,000 for electric,
natural gas, and industrial steam, respectively. An earlier electric earnings
complaint filed by the PSC staff, requesting a reduction of $6.4 million, was
consolidated with our electric case.
Stipulated agreements were reached between the parties to the cases and were
approved by the PSC. Under the agreements, we reduced annual electric revenues
by $2.5 million and annual steam revenues by $25,000 effective for service
rendered after October 30, 1999. There were no changes in natural gas prices.
Included in the PSC Order were regulatory accounting policies which were
different from our current accounting policies. These differences primarily
related to the recognition of pension expense, other post-employment benefits
expense, and deferred income tax expense. As a result, the recognition of these
expenses in November and December followed the accounting treatment mandated by
the PSC Order. The revenue reductions and accounting changes required by the
agreements had a negligible effect on 1999 results and are expected to reduce
net income approximately $300,000 annually.
ENVIRONMENTAL ISSUES -- We are subject to various environmental regulations,
including those related to air and water quality, polychlorinated biphenyl, ash
removal, and asbestos. Routine testing and maintenance programs have been put in
place to comply with these regulations.
We continue to plan and implement projects to meet the Phase II acid deposition
control provisions of the Clean Air Act Amendments of 1990, which establish
standards for electric utilities to reduce certain emissions from coal-fired
generating stations. Final compliance with this legislation becomes effective in
2000. Missouri's air quality law is in compliance with, and does not contain
requirements that are more stringent than, the federal legislation.
While the Iatan plant meets the Phase II requirements, the Lake Road plant is
completing modifications to meet the stricter standards. Alterations to the
plant's main generating units have been made, an electrostatic precipitator was
modified, and a continuous emissions monitoring system and flue gas conditioning
system were installed to allow for the use of low-sulfur coal. Modifications to
the ash handling system and rail modifications that allow coal deliveries by
unit train have also been made.
The Missouri Department of Natural Resources (MDNR) has found that the
ground-level concentration of sulfur dioxide (SO2) near the Lake Road plant
exceeded the limit set by the National Ambient Air Quality Standards (NAAQS)
twice in 1997 and once in 1998. The maximum allowed is once per year. We have
conducted dispersion air modeling to identify appropriate SO2 emission control
measures. Based on the modeling, we have provided the MDNR with a plan to
achieve NAAQS compliance. We have commenced implementation of the plan to assure
that no further violations occur while we negotiate a consent agreement with the
MDNR and the United States Environmental Protection Agency (EPA). We experienced
no additional violations in 1999.
We expect total future capital expenditures of about $800,000 in 2000 to meet
the above Clean Air Act requirements.
In 1998, the EPA issued a nitrogen oxide (NOx) State Implementation Plan (SIP)
call under which Missouri, twenty-one other eastern and midwestern states, and
the District of Columbia are required to revise their SIPs to establish more
stringent emission standards for NOx. This was being done primarily to help the
northeastern states meet the NAAQS for ozone. The EPA determined that the
transport of NOx (a precursor of ozone) from neighboring states is the major
cause of ozone non-compliance in the northeastern states. In March 2000, the
D.C. Circuit Court of Appeals ruled on a case challenging the EPA's SIP call.
Although the D.C. Circuit Court decided for the EPA with regard to the issues
involving other states, the Court decided in favor of the western Missouri
utilities, including St. Joseph Light & Power Company, and vacated the NOxSIP
call for Missouri. The EPA can appeal or request a rehearing on the Missouri
issues.
A regional NOx issue emerged in 1999 due to the inability of the St. Louis area
to comply with the NAAQS for ozone. To address this problem, the MDNR has issued
a proposed NOx reduction regulation for Missouri somewhat similar in nature to
the EPA's NOx SIP call. The reduction levels in
11
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
the proposed regulation are less stringent than the NOx SIPcall and allow for
smaller reductions in the western part of the state than the eastern part of the
state. If approved, the regulation would require compliance by 2003. The full
extent of how we will be affected and the related cost of implementation are not
yet known.
The Kyoto Protocol to the United Nations global warming treaty mandates that the
U.S. reduce its overall greenhouse gas emissions 7% below 1990 levels over the
period 2008-2012. Most observers believe the Protocol will not be ratified by
the U.S. Congress in its present form. A study by Energy Security Analysis Inc.
indicates that the treaty could cost the utility industry $10 billion annually
by 2010, primarily in higher fuel costs. We cannot currently estimate the
treaty's impact on us; however, it could have a significant continuing impact on
our results of operations and financial position.
CAPACITY -- In 1996, we signed a long-term contract to purchase both capacity
and energy beginning in mid-2000 and running through mid-2011. In the first year
of the contract, we will receive 60 megawatts (mw) of electricity. This will
increase by 10 mw each year until it reaches 100 mw in 2004 and remains at that
level for the remainder of the contract. Fixed charges under this contract total
$40 million for the five years ending in 2004. We believe that this contract
will enable us to economically provide for the growing demand in our service
territory.
In addition, we are a member of the MAPP Reliability Council and reserve sharing
pool (MRC). The 34 utility members of the MRC combine their generating resources
to provide emergency replacement energy to each other in the event of an
unscheduled generator outage.
Impact of the Year 2000 Issue -- The Year 2000 issue was the result of computer
programs written using two digits rather than four to define a year. Computer
programs that have date-sensitive software might have recognized a date using
"00" as 1900 rather than 2000. Additionally, other equipment with microchips
with embedded logic, may have failed to function correctly after December 31,
1999, resulting in system failure or miscalculations causing disruptions of
operations.
We believe that the Year 2000 issue has been mitigated with no significant
adverse effect on customers or disruption to business operations. We have not
encountered any significant system problems, nor have we experienced any
interruptions of service to our customers, associated with the year 2000 issue.
Expenses incurred through December 31, 1999 for the efforts related to Year 2000
issues were about $600,000, excluding the costs of redeployment of existing
resources. No significant additional costs are expected to be incurred.
Because of the unprecedented nature of the Year 2000 issue, associated risks may
still exist. All business units have contingency plans to cover essential
business functions for possible Year 2000 related failures.
FORWARD-LOOKING INFORMATION -- This report contains information based on
projections and estimates made by management, which involve risks and
uncertainties. Some of the important factors which could cause actual results to
differ materially from those anticipated include, but are not limited to, future
national and regional economic conditions, inflation rates, regulatory changes
(including, but not limited to, ongoing state and federal activities with
respect to electric utility deregulation, competition, and restructuring),
weather conditions, financial market conditions, interest rates, Year 2000
issues, future business decisions, and other uncertainties, all of which are
difficult to predict and many of which are beyond our control.
12
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES:
Electric utility $ 90,499,000 $ 89,678,000 $ 86,910,000
Other utility 10,898,000 10,876,000 11,948,000
Manufacturing 19,552,000 23,820,000 17,307,000
------------- ------------- -------------
120,949,000 124,374,000 116,165,000
------------- ------------- -------------
OPERATING EXPENSES:
Production fuel 21,200,000 19,964,000 19,166,000
Purchased power 12,708,000 9,896,000 8,307,000
Gas purchased for resale 2,278,000 2,481,000 3,456,000
Manufacturing cost of goods sold 16,300,000 19,868,000 14,864,000
Other operations 21,144,000 22,749,000 21,596,000
Merger-related expenses 3,141,000 105,000 --
Maintenance 8,312,000 8,472,000 7,976,000
Depreciation 12,084,000 11,535,000 11,045,000
Taxes other than income taxes 7,224,000 7,117,000 6,767,000
------------- ------------- -------------
104,391,000 102,187,000 93,177,000
------------- ------------- -------------
OPERATING INCOME 16,558,000 22,187,000 22,988,000
INTEREST CHARGES, NET:
Long-term debt 5,652,000 6,057,000 6,182,000
Notes payable 1,453,000 562,000 181,000
Other 267,000 320,000 192,000
Allowance for borrowed funds used during construction (60,000) (152,000) (75,000)
------------- ------------- -------------
7,312,000 6,787,000 6,480,000
------------- ------------- -------------
OTHER INCOME 507,000 847,000 440,000
------------- ------------- -------------
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST 9,753,000 16,247,000 16,948,000
INCOME TAXES 3,705,000 5,512,000 6,214,000
------------- ------------- -------------
INCOME BEFORE MINORITY INTEREST 6,048,000 10,735,000 10,734,000
MINORITY INTEREST IN INCOME (LOSS) OF SUBSIDIARY (79,000) 71,000 (106,000)
------------- ------------- -------------
NET INCOME $ 6,127,000 $ 10,664,000 $ 10,840,000
------------- ------------- -------------
------------- ------------- -------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 8,212,108 8,099,928 7,988,714
BASIC EARNINGS PER SHARE $ .75 $ 1.32 $ 1.36
------------- ------------- -------------
DILUTED EARNINGS PER SHARE $ .74 $ 1.31 $ 1.36
------------- ------------- -------------
------------- ------------- -------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
13
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31 1999 1998
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
- --ASSETS--
PROPERTY, PLANT AND EQUIPMENT:
Electric utility plant $ 333,513,000 $ 324,621,000
Other 20,912,000 20,377,000
------------- -------------
354,425,000 344,998,000
Less - Reserves for depreciation (178,057,000) (167,112,000)
------------- -------------
176,368,000 177,886,000
Construction work in progress 5,661,000 3,669,000
------------- -------------
182,029,000 181,555,000
OTHER INVESTMENTS 6,741,000 4,922,000
CURRENT ASSETS:
Cash and cash equivalents 354,000 371,000
Accounts receivable, net of reserves of $310,000 and $282,000 10,014,000 10,160,000
Accrued utility revenue 3,306,000 3,674,000
Manufacturing inventories, at first-in first-out cost 3,187,000 2,911,000
Fuel, at average cost 4,641,000 3,366,000
Materials and supplies, at average cost 5,626,000 5,674,000
Prepayments and other 3,100,000 1,902,000
------------- -------------
30,228,000 28,058,000
DEFERRED CHARGES:
Debt expense, being amortized over term of debt 1,249,000 1,349,000
Lease payments receivable 3,042,000 3,166,000
Prepaid pension expense 20,001,000 16,389,000
Regulatory assets 16,446,000 13,843,000
Other 1,590,000 1,973,000
------------- -------------
42,328,000 36,720,000
------------- -------------
$ 261,326,000 $ 251,255,000
------------- -------------
------------- -------------
- --CAPITALIZATION AND LIABILITIES--
CAPITALIZATION:
Common stock $ 33,816,000 $ 33,816,000
Retained earnings 71,376,000 73,450,000
Other paid-in capital 2,879,000 1,877,000
Less - Treasury stock (11,883,000) (13,338,000)
------------- -------------
96,188,000 95,805,000
Long-term debt 68,597,000 73,515,000
------------- -------------
164,785,000 169,320,000
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY 1,313,000 1,369,000
CURRENT LIABILITIES:
Outstanding checks in excess of cash balances 3,611,000 3,512,000
Current maturities of long-term obligations 5,685,000 1,213,000
Accounts payable 9,395,000 9,988,000
Notes payable 17,762,000 7,290,000
Accrued income and general taxes 398,000 823,000
Accrued interest 1,983,000 1,923,000
Accrued vacation 1,247,000 1,233,000
Other 686,000 679,000
------------- -------------
40,767,000 26,661,000
NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
Capital lease obligations 2,697,000 2,902,000
Deferred income taxes 32,610,000 31,822,000
Investment tax credit 3,280,000 3,689,000
Accrued claims and benefits 1,586,000 1,833,000
Deferred interest 2,021,000 2,138,000
Regulatory liabilities 8,812,000 8,440,000
Other 3,455,000 3,081,000
------------- -------------
54,461,000 53,905,000
------------- -------------
COMMITMENTS AND CONTINGENCIES (NOTE 7) $ 261,326,000 $ 251,255,000
------------- -------------
------------- -------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
14
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 6,127,000 $ 10,664,000 $ 10,840,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 12,611,000 12,346,000 11,440,000
Pension expense (3,024,000) (2,228,000) (1,961,000)
Deferred taxes and investment tax credit 740,000 812,000 402,000
Allowance for equity funds used during construction (111,000) (249,000) (129,000)
Net changes in working capital items
not considered elsewhere:
Accounts receivable and accrued utility revenue 514,000 (727,000) 591,000
Inventories (1,503,000) 405,000 (255,000)
Accounts payable and outstanding checks (494,000) (1,188,000) (2,804,000)
Accrued income and general taxes (1,202,000) 88,000 234,000
Other, net (342,000) (118,000) (147,000)
Net changes in regulatory assets and liabilities (2,593,000) 535,000 464,000
Net changes in other assets and liabilities 12,000 266,000 (98,000)
----------- ----------- -----------
Net cash provided by operating activities 10,735,000 20,606,000 18,577,000
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to plant (13,124,000) (16,843,000) (14,128,000)
Allowance for borrowed funds used during construction 60,000 152,000 75,000
Investments (1,818,000) 202,000 2,996,000
Other 52,000 97,000 (18,000)
----------- ----------- -----------
Net cash used in investing activities (14,830,000) (16,392,000) (11,075,000)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Lines of credit increase (decrease) 10,472,000 6,811,000 (462,000)
Principal payments under capital lease obligations (205,000) (191,000) (178,000)
Long-term debt retired (2,416,000) (7,873,000) (1,358,000)
Long-term debt issued 1,971,000 3,087,000 --
Common stock purchased -- -- (4,000)
Common stock issued 2,457,000 1,901,000 1,821,000
Dividends paid (8,201,000) (7,928,000) (7,659,000)
----------- ----------- -----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 4,078,000 (4,193,000) (7,840,000)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (17,000) 21,000 (338,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 371,000 350,000 688,000
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 354,000 $ 371,000 $ 350,000
----------- ----------- -----------
----------- ----------- -----------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
CASH PAID DURING THE YEAR FOR:
Interest $ 7,195,000 $ 6,677,000 $ 7,444,000
Income taxes, net of refunds 4,385,000 4,588,000 5,609,000
</TABLE>
For purposes of the Consolidated Statements of Cash Flows, the Company considers
all highly liquid debt instruments purchased with an original maturity of three
months or less to be cash equivalents.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
15
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31 1999 1998
- ------------------------------------------------------------------------------------
<S> <C> <C>
COMMON EQUITY:
Common stock - authorized 25,000,000 shares,
without par value; issued 9,252,748 shares $ 33,816,000 $ 33,816,000
Retained earnings 71,376,000 73,450,000
Other paid-in capital (principally gain on
issuance of treasury stock) 2,879,000 1,877,000
Less - Treasury stock, at cost, 985,200 and
1,105,821 shares (11,883,000) (13,338,000)
------------- -------------
96,188,000 95,805,000
LONG-TERM DEBT:
First mortgage bonds -
9.44% series due February 1, 2021 22,500,000 22,500,000
Unsecured pollution control revenue bonds -
5.85% series due February 1, 2013 5,600,000 5,600,000
Unsecured medium-term notes -
7.13% due November 29, 2013 1,000,000 1,000,000
7.16% due November 29, 2013 9,000,000 9,000,000
7.17% due December 1, 2023 7,000,000 7,000,000
7.33% due November 30, 2023 3,000,000 3,000,000
8.36% due March 15, 2005 20,000,000 20,000,000
------------- -------------
40,000,000 40,000,000
Other long-term debt 6,182,000 6,628,000
------------- -------------
74,282,000 74,728,000
Less - Current maturities (5,685,000) (1,213,000)
------------- -------------
68,597,000 73,515,000
------------- -------------
Total capitalization $ 164,785,000 $ 169,320,000
------------- -------------
------------- -------------
</TABLE>
Notes:
(a) Common Stock:
At December 31, 1999, there were 8,267,548 shares of common stock
outstanding.
St. Joseph Light &Power Company (the Company) has an Automatic Dividend
Reinvestment and Optional Cash Payment Plan. Under this Plan, common shares
may be newly issued, reissued or purchased on the open market.
At December 31, 1999, the Company had 246,550 shares of common stock
reserved for this Plan. In addition, the Company has 371,524 shares of stock
reserved for its stock-based compensation plans. Refer to Note 3 in the
Notes to Consolidated Financial Statements.
At December 31, 1999, there were 8,267,548 Rights outstanding. Each Right
entitles the holder thereof to purchase one-half share of common stock at a
price of $35 per one-half share.
The Rights, which expire on December 4, 2006, have no voting rights. The
Rights are exercisable in the event of certain attempted business
acquisitions. Exercising the Rights will cause substantial dilution to a
person or group attempting to acquire the Company on terms not approved by
the Company's board of directors. The Rights Agreement is inoperable with
respect to the proposed merger agreement. Refer to Note 1 in the Notes to
Consolidated Financial Statements.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
16
<PAGE>
(b) Long-Term Debt:
The first mortgage bonds are secured equally and ratably by a direct lien on
substantially all fixed property and franchises now owned or hereafter
acquired.
Other long-term debt includes notes payable to banks and finance companies
which are payable through 2003 and bear interest at rates ranging from
9.635% to 9.75% and prime plus 1.5% to prime plus 2.75%. These notes are
collateralized by substantially all of the assets of Percy Kent Bag Co.,
Inc. (Percy Kent). Refer to Note 1 in the Notes to Consolidated Financial
Statements.
The combined aggregate amount of maturities and unfulfilled sinking fund
requirements for the next five years are as follows:
<TABLE>
<S> <C>
2000 $ 5,685,000
2001 404,000
2002 1,152,000
2003 1,192,000
2004 1,125,000
-----------
$ 9,558,000
-----------
-----------
</TABLE>
(c) Cumulative Preferred Stock:
Cumulative preferred stock of 4,000,000 shares, without par value, is
authorized.
(d) Preference Stock:
Preference stock of 2,000,000 shares, without par value, is authorized.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31 1999 1998 1997
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $ 73,450,000 $ 70,714,000 $ 67,533,000
NET INCOME 6,127,000 10,664,000 10,840,000
------------ ------------ ------------
79,577,000 81,378,000 78,373,000
LESS - Dividends on common stock of $1.00, $.98
and $.96 per share (8,201,000) (7,928,000) (7,659,000)
------------ ------------ ------------
BALANCE AT END OF YEAR $ 71,376,000 $ 73,450,000 $ 70,714,000
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
17
<PAGE>
CONSOLIDATED STATEMENTS OF TAXES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
COMPONENTS OF INCOME TAX EXPENSE:
Taxes payable currently --
Federal $ 2,570,000 $ 4,156,000 $ 5,025,000
State 395,000 544,000 787,000
------------ ----------- ------------
2,965,000 4,700,000 5,812,000
Provisions for deferred taxes (a) --
Depreciation and other plant-related differences (b) (54,000) 648,000 255,000
Pensions 1,383,000 1,072,000 971,000
Other (179,000) (501,000) (417,000)
------------ ----------- ------------
1,150,000 1,219,000 809,000
Amortization of investment tax credits (410,000) (407,000) (407,000)
------------ ----------- ------------
Total income tax expense $ 3,705,000 $ 5,512,000 $ 6,214,000
------------ ----------- ------------
------------ ----------- ------------
RECONCILIATION OF INCOME TAX RATES:
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income tax benefit for deduction of
federal income taxes (1.8) (1.8) (1.8)
Timing differences flowed through as required
by regulators 2.3 1.8 1.2
Amortization of investment tax credits (4.2) (2.5) (2.4)
Amortization of excess deferred taxes (1.3) (1.3) (1.0)
State income taxes, net of federal income tax benefit 6.5 5.6 5.8
Non-deductible merger expenses 7.3 -- --
Tax on contribution in aid of construction paid by customer (2.2) -- --
Other (3.9) (2.7) (.4)
------------ ----------- ------------
Effective income tax rate (c) 37.7% 34.1% 36.4%
------------ ----------- ------------
------------ ----------- ------------
</TABLE>
Notes:
(a) The Company has recorded regulatory assets and liabilities to account for
the effect of expected future regulatory actions related to unamortized
investment tax credits, income tax liabilities recorded at tax rates in
excess of current rates, and other items for which deferred taxes have not
previously been provided. The principal components of the Company's deferred
income tax balances consist of the following:
<TABLE>
<CAPTION>
DECEMBER 31 1999 1998
- -------------------------------------------------------------------------
<S> <C> <C>
Accelerated depreciation and other
plant-related differences $ 24,669,000 $ 24,934,000
Pensions 7,650,000 6,265,000
Unamortized investment tax credits (2,299,000) (2,552,000)
Regulatory assets 12,811,000 12,802,000
Regulatory liabilities (6,513,000) (5,888,000)
Net operating loss carryforwards of
Percy Kent, which expire through 2019 (2,100,000) (2,060,000)
Other, net (1,608,000) (1,679,000)
------------ ------------
Net deferred tax liabilities $ 32,610,000 $ 31,822,000
------------ ------------
------------ ------------
</TABLE>
(b) The Company has elected, for tax purposes, to apply various accelerated
depreciation methods allowed by the Internal Revenue Code.
(c) The effective income tax rate is computed by dividing total income tax
expense by the sum of tax expense and net income.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
18
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 STATEMENT OF ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements include the
accounts of St. Joseph Light & Power Company, a public utility, and its wholly
owned subsidiary, SJLP Inc. and its subsidiary, Percy Kent. Collectively, these
entities are referred to as the "Company." All significant intercompany
transactions have been eliminated in consolidation.
The Company is engaged principally in the generation, purchase, transmission,
distribution, and sale of electricity, the generation and distribution of
industrial steam, and the distribution of natural gas. SJLP Inc. was formed in
September 1996, to pursue investments in non-utility areas. Effective May 31,
1997, SJLPInc. acquired a controlling interest in Percy Kent, a manufacturer of
multiwall and small paper bags.
The acquisition was accounted for as a purchase. Acquired goodwill of
$1,211,000, net of amortization, is included in other deferred charges in the
Consolidated Balance Sheets and is being amortized on a straight-line basis over
15 years. The consolidated financial statements include the results of
operations since the date of acquisition. Pro forma financial data prior to the
date of acquisition do not materially differ from reported results.
On March 4, 1999, the Company and UtiliCorp United Inc. (UtiliCorp) entered into
an Agreement and Plan of merger to form a strategic business combination. Under
terms of the Agreement, each share of common stock of the Company, valued at $23
per share, will be exchanged for shares of UtiliCorp common stock. The Agreement
was approved by a vote of the Company's shareholders at a special meeting in
1999, and by the Public Utility Commissions of Colorado, West Virginia, Iowa,
and Minnesota. The transaction is subject to several additional closing
conditions, including approvals by the Federal Energy Regulatory Commission
(FERC), the Department of Justice, the Federal Communications Commission, and
the Missouri Public Service Commission (PSC). The PSC has scheduled hearings for
mid-July 2000. Management expects the merger to be completed in the fall of
2000. Additional merger-related expenses are expected to be incurred in 2000,
resulting in an after tax impact to earnings of approximately $4.5 million.
The Merger Agreement limits the Company's ability to do certain things prior to
closing, including issue or redeem securities, merge with any entity or make
acquisitions, incur material liens, and declare or pay dividends other than
regular cash dividends.
PROPERTY, PLANT AND EQUIPMENT -- Property, plant and equipment is stated at
original cost. These costs include payroll-related costs such as taxes, pensions
and other fringe benefits, and allowance for funds used during construction
(AFUDC).
Improvements to units of property are capitalized. Utility property units
retired are charged to accumulated depreciation together with any related
removal costs, net of salvage. Maintenance costs and replacements of assets
which do not constitute units of property are expensed as incurred.
DEPRECIATION -- Provisions for utility depreciation have been computed on a
straight-line basis by applying rates approved by the PSC to the classified
account balances. The Company's annual depreciation provisions (including
amounts classified elsewhere in the Consolidated Statements of Income), as a
percentage of the average balance of depreciable property, were 3.7% for 1999,
1998 and 1997.
Percy Kent management has reevaluated and extended the estimated useful lives of
its printing and production equipment to reflect reduced utilization of the
equipment. In conjunction with the decision to extend the lives, management
began depreciating the remaining book value over the anticipated remaining
machine hours which resulted in an increase to the Company's consolidated net
income of approximately $200,000 in 1999.
JOINTLY OWNED IATAN PLANT -- The Company has an agreement with Kansas City Power
and Light Company and The Empire District Electric Company for joint ownership
of a coal-burning generating plant in Iatan, Missouri. The Company's share of
operating expenses for Iatan is included in operating expenses in the
Consolidated Statements of Income. The amounts below represent the Company's 18%
interest in the 670-megawatt unit:
<TABLE>
<CAPTION>
DECEMBER 31 1999 1998
-------------------------------------------------------------
<S> <C> <C>
Electric utility plant $ 61,553,000 $ 61,541,000
Reserves for depreciation 37,348,000 35,339,000
</TABLE>
REVENUE RECOGNITION -- Utility revenues relating to service rendered but
unbilled are recognized in the period the service is provided. Manufacturing
revenues are recognized at the time the finished bags are shipped to the
customer.
19
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EARNINGS PER SHARE -- Basic and diluted earnings per average common share were
computed by dividing net income by the following:
<TABLE>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Denominator for basic EPS - Weighted average number
of shares of common stock outstanding during the year 8,212,108 8,099,928 7,988,714
Stock options (see Note 3) 16,535 13,578 7,550
Contingently issuable shares pursuant to long-term
incentive plan (see Note 3) 18,199 15,423 --
--------- --------- ---------
Denominator for diluted EPS 8,246,842 8,128,929 7,996,264
--------- --------- ---------
--------- --------- ---------
</TABLE>
ACCOUNTING POLICIES -- 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 and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities." In June 1999, the FASB issued Statement
137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral
of the Effective Date of SFAS 133." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting.
SFAS 133, as amended, is effective for fiscal years beginning after June 15,
2000. A company may also implement the Statement as of the beginning of any
fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998
and thereafter). SFAS 133 cannot be applied retroactively.
The Company believes its fixed-price contracts for future purchases of energy,
fossil fuels, and rail service are not derivatives as defined in SFAS 133
because there are no net settlement features. The Company's investments include
debt with detachable warrrants. SFAS 133 will require such securities to be
accounted for as two separate instruments: a warrant for the issuer's stock and
a plain interest-bearing security. SFAS 133 will require changes in the fair
value of the separated warrants to be reported currently in earnings. There is
no public market for such warrants or for the debt or common stock of the
investee, however, the excess of the fair value of the warrants over the
exercise price is currently estimated to be $4.1 million. Refer to Note 5, Fair
Value of Financial Instruments.
The Company is continuing to study the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of its adoption of SFAS
133. However, the Statement could increase volatility in earnings and other
comprehensive income.
RECLASSIFICATIONS -- Certain reclassifications have been made in the financial
statements to enhance comparability.
2 BENEFIT PLANS
RETIREMENT SAVINGS PLAN -- The Company has a Retirement Savings Plan under
Section 401(k) of the Internal Revenue Code. The plan covers all employees.
Under this plan, eligible employees may defer and contribute a portion of
current compensation in order to supplement retirement benefits. The Company
makes a matching contribution for employees with one year or more of service of
50 percent of employee contributions, up to 6 percent of compensation, on a
monthly basis. The Company made contributions of $425,000 for 1999, $359,000 for
1998, and $300,000 for 1997.
PENSION AND POSTRETIREMENT BENEFIT PLANS -- The Company has two non-contributory
defined benefit pension plans, one for bargaining and one for non-bargaining
employees, covering all employees with one year or more of continuous service.
Benefits for both plans are based on years of service and compensation,
utilizing the final average-pay benefit formula. The Company's funding policy is
to comply with the minimum funding requirements of the Employee Retirement
Income Security Act.
20
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition to providing pension benefits, the Company provides certain
postretirement medical and life insurance benefits (OPEB). Employees hired after
December 31, 1992 are not eligible for postretirement life insurance benefits.
Employees covered under the plans become eligible for these benefits if they
reach retirement age while working for the Company and have 10 years of service.
The Company uses Voluntary Employees' Beneficiary Association trusts, which
cover substantially all active and retired employees.
The following table summarizes the net pension credits and postretirement
benefit costs, including amounts capitalized:
<TABLE>
<CAPTION>
PENSION OPEB
1999 1998 1997 1999 1998 1997
------------------------------------- -------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost--benefits earned during the period $ 1,050,000 $ 977,000 $ 861,000 $ 257,000 $ 216,000 $ 149,000
Interest cost on benefit obligation 2,559,000 2,433,000 2,280,000 855,000 733,000 672,000
Expected return on plan assets (5,976,000) (5,392,000) (4,755,000) (332,000) (229,000 (169,000)
Amortization of transition (asset) obligation (431,000) (431,000) (431,000) 388,000 388,000 388,000
Amortization of prior service cost 249,000 223,000 175,000 -- -- --
Recognized net actuarial (gain) loss (1,063,000) (627,000) (551,000) 21,000 -- --
----------- ----------- ----------- ----------- --------- ---------
(3,612,000) (2,817,000) (2,421,000) 1,189,000 1,108,000 1,040,000
Amounts credited (charged) to construction 588,000 589,000 460,000 (194,000) (232,000) (198,000)
----------- ----------- ----------- ---------- ---------- ----------
Net benefit costs (credits) included
in operating expenses $(3,024,000) $(2,228,000) $(1,961,000) $ 995,000 $ 876,000 $ 842,000
----------- ----------- ----------- ---------- ---------- ----------
----------- ----------- ----------- ---------- ---------- ----------
</TABLE>
The following table reconciles the beginning and ending balances of the plans'
benefit obligations and fair value of plan assets and reconciles the funded
status of the plans to the related amounts recognized in the Consolidated
Balance Sheets:
<TABLE>
<CAPTION>
PENSION OPEB
1999 1998 1999 1998
----------------------------- -----------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 34,860,000 $ 32,643,000 $ 10,593,000 $ 10,140,000
Service cost--benefits earned during period 1,050,000 977,000 257,000 216,000
Interest cost on benefit obligation 2,559,000 2,433,000 855,000 733,000
Actuarial (gains) losses (3,124,000) 350,000 365,000 (55,000)
Plan amendments 337,000 633,000 -- --
Participant contributions -- -- 216,000 222,000
Benefits paid and other expenses (2,238,000) (2,176,000) (1,041,000) (663,000)
------------ ------------ ------------ ------------
Benefit obligation at end of year $ 33,444,000 $ 34,860,000 $ 11,245,000 $ 10,593,000
Change in plan assets:
Fair value of plan assets at beginning of year $ 67,456,000 $ 60,971,000 $ 4,064,000 $ 2,783,000
Actual return on plan assets 9,356,000 8,661,000 430,000 588,000
Employer contribution -- -- 1,237,000 1,134,000
Participant contributions -- -- 216,000 222,000
Benefits paid and other expenses (2,238,000) (2,176,000) (1,041,000) (663,000)
------------ ------------ ------------ ------------
Fair value of plan assets at end of year $ 74,574,000 $ 67,456,000 $ 4,906,000 $ 4,064,000
Funded status:
Plan assets in excess of (less than) benefit
obligation $ 41,130,000 $ 32,596,000 $ (6,339,000) $ (6,529,000)
Unrecognized net actuarial (gain) loss (22,309,000) (16,868,000) 222,000 (23,000)
Unrecognized transition (asset) obligation (863,000) (1,294,000) 5,019,000 5,407,000
Unrecognized prior service cost 2,043,000 1,955,000 -- --
------------ ------------ ------------ ------------
Prepaid (accrued) benefit cost $ 20,001,000 $ 16,389,000 $ (1,098,000) $ (1,145,000)
Assumptions as of December 31:
Discount rate 8.00% 7.25% 8.00% 7.25%
Expected return on plan assets 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase 4.30% 4.30% N/A N/A
</TABLE>
For measurement purposes, a 7.5 percent annual rate of increase in the
per-capita health care benefits was assumed for 2000; the rate was assumed to
decrease gradually to 6 percent by 2020 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1-PERCENTAGE- 1-PERCENTAGE-
POINT INCREASE POINT DECREASE
<S> <C> <C>
Effect on total of service and interest cost components $ 248,000 $ 195,000
Effect on postretirement benefit obligation $1,994,000 $1,617,000
</TABLE>
21
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3 STOCK-BASED COMPENSATION PLANS
The Company has a long-term stock incentive plan (the Plan). Under the Plan,
non-employee directors are automatically granted restricted stock and
non-qualified options to purchase shares of common stock. All options are
exercisable in full from the date of grant and have exercise prices equal to the
stock's market price on the date of the grant. The options will expire at the
end of six months after the close of the merger with UtiliCorp.
The following table is a summary of data regarding stock options and restricted
stock for non-employee directors:
<TABLE>
<CAPTION>
1999 1998 1997
---------------------------------------------------------
SHARES PRICE1 SHARES PRICE1 SHARES PRICE1
<S> <C> <C> <C> <C> <C> <C>
Options outstanding at January 1 121,000 $15.660 123,000 $15.250 106,000 $15.125
Options granted 16,000 20.875 16,000 18.313 17,000 16.030
Options exercised -- N/A 18,000 15.222 -- N/A
------- ------- ------- ------- ------- -------
Options outstanding at December 31 137,000 $16.269 121,000 $15.660 123,000 $15.250
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Restricted shares granted and compensation 3,000 $63,000 3,000 $55,000 2,500 $40,000
expense, respectively
</TABLE>
- ----------
1weighted average exercise price
The Company accounts for the option feature of the Plan under Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees," under
which no compensation cost has been recognized. The following table shows the
assumptions made for grants in each year, as well as the amounts the Company's
net income and earnings per share would have been had compensation cost for this
plan been recorded consistent with SFAS 123, "Accounting for Stock-Based
Compensation," using the Black-Scholes pricing model:
<TABLE>
<CAPTION>
1999 1998 1997
---------------------------------------------------
<S> <C> <C> <C>
Net income: As reported $6,127,000 $10,664,000 $10,840,000
Pro forma 6,096,000 10,640,000 10,815,000
Basic EPS: As reported $.75 $1.32 $1.36
Pro forma .74 1.31 1.35
Diluted EPS: As reported .74 1.31 1.36
Pro forma .74 1.31 1.35
Risk-free interest rate 5.94% 5.81% 6.89%
Expected dividend yield 5.50% 5.83% 5.79%
Expected life 10 years 10 years 10 years
Expected volatility 20% 19% 18%
Weighted average fair value of options granted $3.14 $2.42 $2.37
</TABLE>
The Plan also covers long-term incentives for officers and certain other key
employees. It provides for overlapping three-year performance cycles with stock
awards established on the first day and earned on the last day of each
performance cycle. Compensation of $721,000, $132,000, and $(9,000) was expensed
for this portion of the Plan in 1999, 1998, and 1997, respectively.
At December 31,1999, there were 371,524 shares available for grant for
non-employee directors options and restricted stock and for officers and key
employees restricted stock.
All shares of restricted stock will be converted into unrestricted shares of
UtiliCorp common stock as of the closing of the merger.
4 SHORT-TERM BORROWINGS
The Company has arrangements with certain banks to provide unsecured short-term
lines of credit on a committed basis with available amounts at December 31,
1999, totaling $3,000,000. In addition, the Company has agreements with several
banks to borrow, as available, on an uncommitted basis at market-based rates
quoted by the banks. Outstanding notes bear interest at rates based on the prime
rate or money market rates.
At December 31, 1999 and 1998, respectively, outstanding borrowings consisted of
$17,762,000 and $7,290,000 of notes payable to banks with weighted average
interest rates of 6.4% and 6.1%. During 1999 and 1998, weighted average
short-term debt outstanding was $15,531,000 and $1,169,000, with weighted
average interest rates of 5.9% and 6.7%, respectively.
22
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5 FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:
Cash and Temporary Investments -- The fair value of these investments is
estimated based on quoted market prices for the same or similar issues and
approximates the carrying amount.
OTHER INVESTMENTS -- The balance includes investments in convertible securities
of two non-publicly traded companies, a business park joint venture, community
betterment projects, and retirement trusts. A recent sale of stock of one of the
two non-public companies indicates the fair value of the Company's investment in
that entity is $6,400,000. The fair value of the investments in the remaining
convertible securities, the joint venture and the community betterment projects
are stated at the original cost of $1,028,000, $500,000 and $350,000,
respectively, due to the impracticability of estimating the market value. The
fair value of the underlying instruments of the retirement trusts of $3,019,000
is estimated based on quoted market prices for the same or similar issues. The
investment in the trusts is offset by a corresponding liability for future
obligations in other non-current liabilities.
LONG-TERM DEBT -- Most of the Company's long-term debt is not publicly traded;
therefore, a market price does not exist for these instruments. The fair value
of long-term debt is estimated based upon market prices for comparable
securities with similar maturities.
<TABLE>
<CAPTION>
1999 1998
---------------------------------------------------------------------
Carrying Amounts Fair Values Carrying Amounts Fair Values
<S> <C> <C> <C> <C>
Cash and temporary investments $ 354,000 $ 354,000 $ 373,000 $ 373,000
Other investments 6,741,000 11,297,000 4,922,000 5,215,000
Long-term debt 74,282,000 76,046,000 74,728,000 85,739,000
</TABLE>
The difference in carrying amounts and fair values of financial instruments is
not expected to result in a material impact on the Company's financial position
or results of operations. Under the ratemaking principles followed by the PSC,
any gain or loss on early refinancing of the Company's long-term debt would be
used to reduce or increase the Company's rates over a prescribed amortization
period.
6 EFFECTS OF REGULATION
The Company is subject to rate regulation by the PSC. Rates are established to
allow the Company an opportunity to recover its costs and earn a return on its
investment. The Company currently applies SFAS 71, "Accounting for the Effects
of Certain Types of Regulation," which recognizes the economic effects of rate
regulation. In the event the Company determines that it no longer meets the
criteria for following SFAS 71, the accounting impact would be a non-cash charge
to operations of an amount that could be material. Criteria that give rise to
the discontinuance of SFAS 71 include (1) increasing competition that restricts
the Company's ability to establish prices to recover specific costs, and (2) a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The continued applicability
of SFAS 71 is regularly reviewed based on the current regulatory environment.
In March 1997, the PSC opened a docket to investigate restructuring in the
electric utility industry. The Retail Electric Competition Task Force, comprised
of representatives from various groups, was charged with preparing comprehensive
reports to the PSC. The reports were prepared in 1998 based upon a thorough
investigation and study of retail wheeling of electricity and related issues.
Included were recommendations outlining how Missouri should implement retail
electric competition should enabling legislation be enacted.
At the present time, a general consensus exists that the legislature should
first deal with the tax issues associated with restructuring the industry and
then pass a deregulation bill. Since a provision in the Missouri constitution
requires voter approval of new taxes, the various tax issues cannot be addressed
in a deregulation law as has been done in many other states. Failure to make
changes in the way utilities are taxed could result in lower taxes for
competitors not currently regulated by the PSC. We expect that a proposal to
reform utility taxes will be submitted to voters as a constitutional amendment
in November 2000. If voters approve the proposal, a deregulation law could be
passed in the 2001 session. Based on current legislative activity, we believe
that retail competition might begin in Missouri sometime during 2004.
23
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Based on the PSC docket and deregulation plans implemented or considered by
other states, management believes it is most likely that the generation portion
of the business could become unregulated and the transmission and distribution
functions will continue to be regulated.
Based on a current evaluation of the various factors and conditions that are
expected to impact future cost recovery, the Company believes that its
regulatory assets, including those related to generation, are probable of future
recovery and that the utilization of SFAS 71 continues to be appropriate.
Accordingly, the Company has recorded regulatory assets and liabilities on the
Consolidated Balance Sheets, consisting primarily of deferred taxes as noted in
Note(a) to Consolidated Statements of Taxes.
On December 1, 1998, the Company filed separate rate cases before the PSC asking
for price increases of approximately $6,100,000, $500,000, and $275,000 for
electric, natural gas, and industrial steam, respectively. An earlier electric
earnings complaint filed by the PSC staff, requesting a reduction of $6.4
million, was consolidated with the Company's electric case.
Stipulated agreements were reached between the Company and other parties to the
cases and were approved by the PSC. Under the agreements, the Company reduced
annual electric revenues by $2.5 million and annual steam revenues by $25,000
effective for service rendered after October 30, 1999. There were no changes in
natural gas prices. Included in the PSC Order were regulatory accounting
policies which were different from the Company's current accounting policies.
These differences primarily related to the recognition of pension expense, OPEB
expense, and deferred income tax expense. As a result, the recognition of these
expenses in November and December followed the accounting treatment mandated by
the PSC Order. The revenue reductions and accounting changes required by the
agreements had a negligible effect on 1999 results and are expected to reduce
net income approximately $300,000 annually.
7 COMMITMENTS AND CONTINGENCIES
LEASES -- The Company has a 50-year capital lease agreement with six other
regional utilities for a transmission line and related facilities. Electric
utility plant, as of December 31, 1999, includes $2,697,000 for the leased joint
facilities and other property acquired under capital leases. The Company is also
the lessor under 50-year direct financing lease agreements for terminal and
associated joint facilities. The future minimum lease payments and receivables
under these agreements are:
<TABLE>
<CAPTION>
PAYMENTS RECEIVABLES
----------- -------------
<S> <C> <C>
2000 $ 426,000 $ 123,000
2001 267,000 123,000
2002 216,000 123,000
2003 216,000 123,000
2004 216,000 123,000
Later years 5,102,000 2,427,000
---------- -----------
Total minimum lease payments/receivables 6,443,000 3,042,000
Less - Amounts representing interest 3,746,000 2,021,000
---------- -----------
Present value of obligations under capital leases/net receivables $2,697,000 $ 1,021,000
---------- -----------
---------- -----------
</TABLE>
OTHER COMMITMENTS -- The Company's capital budget, excluding AFUDC and including
non-utility investments, for 2000 is approximately $10,944,000. The five-year
capital budget is estimated to be $62,094,000.
The Company has entered into long-term contracts to purchase generating
capacity, fossil fuels, and rail transportation. Minimum annual amounts to be
purchased under these contracts approximate $13,918,000, $13,470,000,
$11,424,000, $12,708,000, and $10,708,000 for each of the next five years,
respectively.
ENVIRONMENTAL CONTINGENCIES -- The Company is required to meet various
environmental regulations governing air and water standards. The Company expects
future capital expenditures of about $800,000 related to compliance with the
Clean Air Act.
The United States Environmental Protection Agency (EPA) has issued a nitrogen
oxide (NOx) State Implementation Plan (SIP) call under which Missouri,
twenty-one other states, and the District of Columbia were required to revise
their SIPs to establish more stringent emission standards for NOx. The Company
joined with five other western Missouri utilities, other states, and private
organizations in a lawsuit challenging the EPA's SIP call. In March 2000, the
D.C. Circuit Court decided for the EPA with regard to the issues involving other
states; however, the Court decided in favor of the western Missouri utilities
and vacated the NOx SIP call for Missouri.
The EPA can appeal or request a rehearing on the Missouri issues.
A regional NOx issue emerged in 1999 due to the inability of the St. Louis area
to comply with the NAAQS for ozone. To address this problem, the Missouri
Department of Natural Resources has issued a proposed NOx reduction regulation
for Missouri somewhat similar
24
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
in nature to the EPA's NOx SIP call. The reduction levels in the proposed
regulation are less stringent than the NOx SIP call and allow for smaller
reductions in the western part of the state than the eastern part of the state.
If approved, the regulation would require compliance by 2003. The full extent of
how we will be affcted and the related cost of implementation are not yet known.
TRANSMISSION REVENUE -- In April 1999, the FERC issued an order directing the
MidContinent Area Power Pool (MAPP), of which the Company is a member, to refund
payments for transmission charges assessed from March 1997 through March 1999.
The FERC disagrees with the method MAPP was using to assess transmission charges
for transactions with non-member entities. Fifteen MAPP transmission providers,
including the Company, filed a petition for rehearing on the FERC's order, which
was denied by the FERC. The Company, therefore, made the required payment and
expensed $597,000 in October 1999. The Company is participating in a joint
appeal of the FERC's order.
OTHER CONTINGENCIES -- Certain legal actions are pending which may impact the
Company. In management's opinion, the ultimate resolution of these matters is
not expected to materially affect the Company's financial position or operating
results.
8 SEGMENTS OF BUSINESS
The Company has two reportable segments: electric utility and manufacturing. The
Company is a public utility engaged primarily in the business of generating and
distributing electric energy in a 10-county area in northwest Missouri. The
Company's 63,000 regulated customers include residential, commercial, and
industrial classes. The Company's manufacturing segment represents a controlling
interest in a company which manufactures multiwall and small paper bags
primarily for food products, agricultural products, specialty chemicals, pet
foods and other consumer packaging. Other operations of the Company include the
limited sale of natural gas and industrial steam, as well as investment in
non-utility businesses.
The accounting policies of the segments are the same as those described in the
summary of significant accounting policies in Note 1. The Company evaluates
performance and allocates resources to its regulated business units based on
profit or loss from operations, not including interest charges or nonrecurring
gains and losses, and on the rate of return achieved. The performance of the
Company's manufacturing segment is evaluated based on net income after taxes and
minority interest.
The following table sets forth certain information regarding the Company's
segments of business:
<TABLE>
<CAPTION>
(IN THOUSANDS) ELECTRIC UTILITY MANUFACTURING ALL OTHER TOTALS
---------------------------------------------------------------
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Revenues from external customers $ 90,499 $ 19,552 $ 10,898 $ 120,949
Depreciation 11,432 618 561 12,611
Income taxes 3,625 -- (25) 3,600
Segment profit (loss) 12,633 (180) 258 12,711
Segment assets 224,359 13,553 17,357 255,269
Expenditures for segment assets, including AFUDC 12,574 180 370 13,124
Net regulatory assets 7,478 -- 156 7,634
Accumulated deferred income taxes and investment tax credits 33,477 -- 2,413 35,890
Other non-cash items--pension expense (2,637) -- (387) (3,024)
YEAR ENDED DECEMBER 31, 1998
Revenues from external customers $ 89,678 $ 23,820 $ 10,876 $ 124,374
Depreciation 10,813 995 538 12,346
Income taxes 5,307 -- (48) 5,259
Segment profit (loss) 15,617 (24) 396 15,989
Segment assets 217,947 13,906 14,804 246,657
Expenditures for segment assets, including AFUDC 15,659 768 416 16,843
Net regulatory assets 5,191 -- 212 5,403
Accumulated deferred income taxes and investment tax credits 33,252 -- 2,259 35,511
Other non-cash items--pension expense (1,941) -- (287) (2,228)
YEAR ENDED DECEMBER 31, 1997
Revenues from external customers $ 86,910 $ 17,307 $ 11,948 $ 116,165
Depreciation 10,409 526 505 11,440
Income taxes 5,881 -- 75 5,956
Segment profit (loss) 16,476 (168) 381 16,689
Segment assets 209,505 15,671 12,848 238,024
Expenditures for segment assets, including AFUDC 13,520 143 465 14,128
Net regulatory assets 4,805 -- 164 4,969
Accumulated deferred income taxes and investment tax credits 31,745 -- 1,986 33,731
Other non-cash items--pension expense (1,716) -- (245) (1,961)
</TABLE>
25
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table reconciles reportable segment profit, assets, depreciation,
and income taxes, disclosed above, to the Company's Consolidated Financial
Statements:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31 (IN THOUSANDS) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Profit
Reportable segment profit $ 12,453 $ 15,593 $ 16,308
Other profit 258 396 381
Interest charges (net)1 (6,650) (5,909) (5,931)
Other income 171 837 340
Income taxes on other income (105) (253) (258)
-------- -------- --------
Consolidated net income $ 6,127 $ 10,664 $ 10,840
-------- -------- --------
-------- -------- --------
Assets
Reportable segment assets $237,912 $231,853 $225,176
Other assets 17,357 14,804 12,848
Temporary and other investments 3,216 2,810 3,923
Debt expense 1,238 1,324 1,437
Other assets not allocated 1,603 464 385
-------- -------- --------
Consolidated assets $261,326 $251,255 $243,769
-------- -------- --------
-------- -------- --------
Depreciation
Reportable segment depreciation $ 12,050 $ 11,808 $ 10,935
Other depreciation 561 538 505
Less--Manufacturing depreciation included in
cost of goods sold (470) (811) (395)
Less--Electric depreciation included in other
operations and maintenance (57) -- --
-------- -------- --------
Consolidated depreciation $ 12,084 $ 11,535 $ 11,045
-------- -------- --------
-------- -------- --------
Income Taxes
Reportable segment income taxes $ 3,625 $ 5,307 $ 5,881
Other income taxes (25) (48) 75
Income taxes on other income 105 253 258
-------- -------- --------
Consolidated income taxes $ 3,705 $ 5,512 $ 6,214
-------- -------- --------
-------- -------- --------
</TABLE>
1 Excludes manufacturing segment interest expense of $662,000, $878,000, and
549,000 for 1999, 1998, and 1997, respectively, as interest expense is included
in manufacturing net income which is the measure of profit or loss used to
evaluate the performance of that segment.
9 QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1999
Operating revenues $ 28,686,000 $ 28,306,000 $ 36,348,000 $ 27,609,000
Operating income 2,588,000 1,796,000 9,998,000 2,176,000
Net income (loss) 414,000 (182,000) 5,404,000 491,000
Weighted average common shares outstanding 8,158,109 8,187,817 8,241,328 8,259,740
Basic earnings per average common share $.05 $(.02) $.66 $.06
Diluted earnings per average common share .05 (.02) .65 .06
1998
Operating revenues $ 29,717,000 $ 30,056,000 $ 37,366,000 $ 27,235,000
Operating income 4,999,000 4,842,000 10,122,000 2,224,000
Net income 2,401,000 1,990,000 5,214,000 1,059,000
Weighted average common shares outstanding 8,056,020 8,092,173 8,114,921 8,135,561
Basic and diluted earnings per average
common share $.30 $.25 $.64 $.13
</TABLE>
The quarterly data reflect seasonal variations common to the utility industry.
Quarterly net income was reduced by after tax merger-related expenses of
$994,000, $1,579,000, $0, and $144,000.
26
<PAGE>
FINANCIAL RESPONSIBILITY / INDEPENDENT AUDIT
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of St. Joseph Light & Power Company is responsible for the
preparation and presentation of the financial information in this Annual Report.
The preceding financial statements have been prepared in accordance with
generally accepted accounting principles consistently applied, and reflect
management's best estimates and informed judgments as required.
To fulfill these responsibilities, management has developed and maintains a
comprehensive system of internal operating, accounting, and financial controls.
These controls provide reasonable assurance that the Company's assets are
safeguarded, transactions are properly recorded, and resulting financial
statements are reliable. An internal audit function assists management in
monitoring the effectiveness of the controls.
The Report of Independent Public Accountants on the financial statements appears
on this page. The responsibility of the independent auditors is limited to the
audit of financial statements presented and the expression of an opinion as to
their fairness.
The Board of Directors maintains oversight of the Company's financial situation
through its monthly review of operations and financial condition and its
selection of the independent auditors. The Audit Committee, comprised of board
members who are not employees or officers of the Company, also meets
periodically with the independent auditors and the Company's internal audit
staff. The auditors have complete access to and meet with the Audit Committee,
without management representatives present, to review accounting, auditing, and
financial matters. Pertinent items discussed at the meetings are reviewed
with the full Board of Directors.
/s/Terry F. Steinbecker
Terry F. Steinbecker
President and Chief Executive Officer
/s/Larry J. Stoll
Larry J. Stoll
Vice President-Finance,Treasurer and Assistant Secretary
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of St. Joseph Light & Power Company:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of St. Joseph Light & Power Company (a Missouri corporation) and
subsidiaries as of December 31, 1999 and 1998, and the related consolidated
statements of income, retained earnings, cash flows, and taxes for each of the
three years in the period ended December 31, 1999. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion of these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of St. Joseph Light & Power
Company and subsidiaries as of December 31, 1999 and 1998, and the results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Kansas City, Missouri
January 21, 2000
27
<PAGE>
DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
- - JOHN P. BARCLAY, JR., 70
Chairman, President and Chief Executive Officer - Wire Rope Corporation of
America, Inc. (Manufacturer and distributor of wire rope and wire rope
products)
St. Joseph, Missouri - Director since 1974.
DEBORAH A. BECK, 52
Senior Vice President - Insurance Operations - Northwestern Mutual Life
Insurance Company (Insurance company)
Milwaukee, Wisconsin - Director since 1997.
- - DANIEL A. BURKHARDT, 52
Principal - The Jones Financial Companies (Investment banking and retail
securities firm)
St. Louis, Missouri - Director since 1988.
JAMES P. CAROLUS, 49
President - Hillyard Industries, Inc. (Manufacturer of maintenance cleaning
products)
St. Joseph, Missouri - Director since 1989.
- - WILLIAM J. GREMP, 57
Investments - Merrill Lynch & Company
Greenwich, Connecticut - Director since 1995.
DAVID W. SHINNEMAN, 61
President, - Shinneman Management Company (Operator of McDonald's
restaurants)
St. Joseph, Missouri - Director since 1994.
- - ROBERT L. SIMPSON, 66
General Partner - St. Joseph Riverboat Partners
(Riverboat casino)
St. Joseph, Missouri - Director since 1983.
GERALD R. SPRONG, 66
President and Chief Executive Officer - The Morris Plan Company of St.
Joseph (Financial management and lending)
St. Joseph, Missouri
Director, Chairman and Chief Executive Officer - First Savings Bank, F.S.B.
(Banking)
Manhattan, Kansas
President and Chief Executive Officer - Noble Properties of Iowa, L.L.C.
(Ownership and management of hotels)
Des Moines, Iowa - Director since 1976.
Terry F. Steinbecker, 54
President and Chief Executive Officer - St. Joseph Light & Power Company
St. Joseph, Missouri - Director since 1985.
- - Member of Audit Committee
OFFICERS
TERRY F. STEINBECKER, 54 - President and Chief Executive Officer
GARY L. MYERS, 46 - Vice President, General Counsel and Secretary
LARRY J. STOLL, 47 - Vice President - Finance, Treasurer and Assistant
Secretary
JOHN A. STUART, 46 - Vice President - Customer Services & Energy Delivery
DWIGHT V. SVUBA, 57 - Vice President - Energy Supply
28
CORPORATE INFORMATION ANNUAL SHAREHOLDERS MEETING
Corporate Offices The annual meeting of shareholders will
520 Francis Street be at 9 a.m., Wednesday, May 17, 2000,
Post Office Box 998 at the Albrecht-Kemper Museum of Art,
St. Joseph, Missouri 2818 Frederick Boulevard, St. Joseph, Missouri.
64502-0998
(816) 387-6434
fax (816) 387-6332 Form 10-k
1-800-367-4562 A copy of the Annual Report to the Securities and
http://www.sjlp.com Exchange Commission, Form 10-K, will be furnished
email: [email protected] without charge to any shareholder upon contacting:
INDEPENDENT PUBLIC ACCOUNTANTS St. Joseph Light &Power Company
Arthur Andersen LLP Investor Relations Department
2301 McGee, Suite 400 520 Francis Street
Kansas City, Missouri 64108 Post Office Box 998
St. Joseph, Missouri 64502-0998
STOCK LISTING AND PRINCIPAL MARKET Access to the Form 10-K is also
New York Stock Exchange available via the internet through
Eleven Wall Street the EDGAR database on the SEC
New York, New York 10005 website at www.sec.gov or on the
Symbol: SAJ Company's website listed at the
left.
COMMON STOCK TRANSFER AGENT AND REGISTRAR* This report and financial
Harris Trust and Savings Bank statements contained herein are
311 West Monroe Street submitted for the general
Chicago, Illinois 60690 information of the security
holders of St. Joseph Light &
Power Company, and are not in
connection with, or to induce, any
sale or offer to sell or to buy
any securities of the Company, or
in connection with preliminary
negotiations for such sale or
purchase.
* On Feb. 1, 2000, Harris Bank announced the sale of its shareholder services
business to Computershare Limited, an Australian company that operates in seven
countries. The transaction is subject to regulatory approval and was expected to
close 45 days from the Feb. 1 announcement.
COMMON STOCK PRICES
<TABLE>
<CAPTION>
High Low
<S> <C> <C>
1999 First quarter $ 21.000 $ 15.500
Second quarter 21.000 20.188
Third quarter 21.188 20.500
Fourth quarter 21.063 20.063
1998 First quarter $ 18.625 $ 17.250
Second quarter 19.000 18.000
Third quarter 19.375 17.813
Fourth quarter 19.125 17.563
DIVIDENDS PER COMMON SHARE
1999 First quarter $ .25
Second quarter .25
Third quarter .25
Fourth quarter .25
-----
$1.00
1998 First quarter $.245
Second quarter .245
Third quarter .245
Fourth quarter .245
-----
$.980
</TABLE>
29
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included or incorporated by
reference in this Form 10-K, into the Company's previously filed
Form S-3 Registration Statements (Registration No. 33-64687 and
No. 333-42875) and previously filed Form S-8 Registration
Statements (Registration No. 33-28109 and No. 333-03839).
Arthur Andersen LLP
Kansas City, Missouri,
March 28, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 182029000
<OTHER-PROPERTY-AND-INVEST> 6741000
<TOTAL-CURRENT-ASSETS> 30228000
<TOTAL-DEFERRED-CHARGES> 42328000
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 261326000
<COMMON> 21933000
<CAPITAL-SURPLUS-PAID-IN> 2879000
<RETAINED-EARNINGS> 71376000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 96188000
0
0
<LONG-TERM-DEBT-NET> 68597000
<SHORT-TERM-NOTES> 17762000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 5685000
0
<CAPITAL-LEASE-OBLIGATIONS> 2697000
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 70397000
<TOT-CAPITALIZATION-AND-LIAB> 261326000
<GROSS-OPERATING-REVENUE> 120949000
<INCOME-TAX-EXPENSE> 3619000
<OTHER-OPERATING-EXPENSES> 104312000
<TOTAL-OPERATING-EXPENSES> 107931000
<OPERATING-INCOME-LOSS> 13018000
<OTHER-INCOME-NET> 421000
<INCOME-BEFORE-INTEREST-EXPEN> 13439000
<TOTAL-INTEREST-EXPENSE> 7312000
<NET-INCOME> 6127000
0
<EARNINGS-AVAILABLE-FOR-COMM> 6127000
<COMMON-STOCK-DIVIDENDS> 8201000
<TOTAL-INTEREST-ON-BONDS> 5646000
<CASH-FLOW-OPERATIONS> 10735000
<EPS-BASIC> .75
<EPS-DILUTED> .74
</TABLE>
