<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 1994 or
-----------------
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
-------- --------
Commission file number 1-3562
------
UTILICORP UNITED INC.
--------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 44-0541877
------------------------------- --------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3000 Commerce Tower, 911 Main, Kansas City, Missouri 64105
-------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (816) 421-6600
--------------
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
<S> <C>
Common Stock, par value $1.00 per share New York, Pacific and Toronto Stock Exchanges
--------------------------------------- ---------------------------------------------
Preference Stock, no par value,
$2.05 Series New York Stock Exchange
------------------------------- ------------------------
Convertible Subordinated Debentures,
6-5/8%, due July, 2011 New York Stock Exchange
------------------------------------ -----------------------
</TABLE>
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 Regulations 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 voting stock held by nonaffiliates of the
registrant is $1,283,191,623 based on the February 17, 1995, New York Stock
Exchange closing price of $28.63.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the close of the latest practicable date.
Class Outstanding at February 28, 1995
----- --------------------------------
Common Stock, par value $1.00 per share 44,827,470
---------------------------------------
The following documents, or parts thereof, are incorporated herein by reference:
Document Where Incorporated
-------- ------------------
1994 Annual Report to Shareholders Parts I, II and IV
1995 Proxy Statement Part III
<PAGE>
UTILICORP UNITED INC.
FORM 10-K
For the fiscal year ended December 31, 1994
TABLE OF CONTENTS
Description Page
----------- ----
PART I
Item 1. Business 2
Item 2. Properties 9
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote
of Security Holders 13
PART II
Item 5. Market for the Company's Common Stock
and Related Stockholder Matters 14
Item 6. Selected Financial Data 14
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
Item 8. Financial Statements and Supplementary Data 14
Item 9. Changes In and Disagreements With
Accountants on Accounting and Financial Disclosure 15
PART III
Item 10. Directors and Executive Officers of
the Company 15
Item 11. Executive Compensation 15
Item 12. Security Ownership of Certain Beneficial
Owners and Management 15
Item 13. Certain Relationships and Related
Transactions 15
PART IV
Item 14. Exhibits, Financial Statement Schedule,
and Reports on Form 8-K 16
Index to Exhibits 19
Signatures 22
1
<PAGE>
UTILICORP UNITED INC.
PART I
ITEM 1. DESCRIPTION OF BUSINESS
GENERAL DEVELOPMENT OF BUSINESS.
UtiliCorp United Inc. (the company) is an energy company which consists of
electric and natural gas utility operations, gas marketing, exploration and
production operations and independent power generation projects. The company
was formed in 1985 from Missouri Public Service Company. Today the company
operates electric and gas utilities in eight states and one Canadian province.
In addition, the company has ownership interests in 16 independent power
projects in various locations in the United States and Jamaica. The company has
various natural gas, natural gas liquids, gas transmission and gathering
operations in Texas and Oklahoma. At December 31, 1994, the company had
approximately 1.2 million utility customers and a total of 4,683 employees.
The utility operating divisions of UtiliCorp are Missouri Public Service,
WestPlains Energy, Peoples Natural Gas, Michigan Gas Utilities, West Virginia
Power, Northern Minnesota Utilities and Kansas Public Service. West Kootenay
Power operates as a Canadian subsidiary. In addition to these utility
operations, the company is active in non-regulated areas that complement the
utility business primarily through two subsidiaries, Aquila Energy Corporation
(Aquila) and UtilCo Group. The company also markets natural gas in the United
Kingdom through several joint ventures and owns a joint venture interest in an
electric utility in New Zealand.
Aquila was originally purchased as part of Peoples Natural Gas. It was made
a wholly-owned subsidiary of UtiliCorp in 1986 to take advantage of the many
marketing and transportation opportunities created by changes in the natural gas
industry. See page 5 for further discussion.
Formed in 1986, UtilCo Group held ownership interests in 16 independent
power projects in six states and Jamaica at December 31, 1994. These projects
have an aggregate capacity of 792 MW. UtilCo Group's ownership interests range
from 21% to 50%, and its share of project assets at the end of 1994 totaled
$379.8 million.
UtiliCorp U.K., Inc., the company's natural gas marketing venture in the
United Kingdom (U.K.), markets natural gas in areas of the U.K. The company and
six regional electric distribution utilities in the U.K. have entered into joint
venture agreements to supply gas to large volume customers in the electric
utilities' service areas through facilities owned by British Gas.
In July 1993, the company finalized a joint venture arrangement with the
Waikato Electricity Authority in New Zealand. Under the arrangement, UtiliCorp
N.Z., Inc., a subsidiary of the company, agreed to purchase a 33% interest in
Waikato-based WEL Energy Group Ltd. (WEL). UtiliCorp N.Z., Inc. paid
$2.7 million at closing and agreed to pay approximately $17 million over time,
as needed for specific investments, upon call of the WEL Board of Directors.
The $17 million was called in December 1994 and paid in February 1995.
The business of the company is seasonal to the extent that weather patterns
have an effect on revenues. The electric revenues of the company's Missouri
Public Service and WestPlains Energy divisions peak during the summer months
while the electric revenues of its West Virginia Power division and the West
Kootenay Power subsidiary peak during the winter months. The company's gas and
energy related businesses revenues peak during the winter months.
The company's strategy is to balance its services by business segment,
region, climate, and regulatory jurisdiction. In pursuit of these goals, the
company actively seeks expansion opportunities in both the regulated and non-
regulated segments of the industry.
2
<PAGE>
In December 1994, the company announced that it was realigning its
operations to take advantage of changes in the company's business environment.
To respond to these changes, the company is realigning its present structure
into four business groups: Energy Delivery will distribute energy to electric
and gas utility customers; Power Services will generate electric power and
maintain related transmission facilities; Energy Resources will market
natural gas and electric power and operate Aquila's other businesses; and
Marketing Services will manage large account sales, new product development and
marketing services under the EnergyOne(SM) brand.
In connection with the operational realignment, the company is currently
in the process of reviewing its key customer and administrative work
practices. As part of this realignment, it is anticipated that certain
functions will be centralized that may result in employee relocations, facility
consolidations and other related changes. Management expects long-term cost
savings to result from this realignment. Realignment costs incurred in the year
ended December 31, 1994 were not significant.
Additional information related to key events in 1994 can be found under
"Key Events of 1994" on page 19 of the company's 1994 Annual Report to
Shareholders. Such information is incorporated by reference herein.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS.
Segment information for the three years ended December 31, 1994 appears in
Note 12 on page 47 of the company's 1994 Annual Report to Shareholders. Such
information is incorporated by reference herein.
NARRATIVE DESCRIPTION OF BUSINESS.
ELECTRIC OPERATIONS
Through three of its divisions, Missouri Public Service ("MPS"), WestPlains
Energy ("WPE") and West Virginia Power ("WVP"), and one subsidiary, West
Kootenay Power, Ltd. ("WKP"), the company serves approximately 426,414 electric
customers in four states and British Columbia.
Over each of the last three years, the largest customer class has been
residential sales which have accounted for approximately 35%, 36% and 35% of
megawatt-hour ("MWH") sales during 1994, 1993 and 1992, respectively, and 44%,
43% and 42% of total electric revenues during the same period. A summary of the
company's electric revenues, MWH sales, and customers, by class is set forth
under "Electric Operations" on page 20 of the company's 1994 Annual Report to
Shareholders. Such information is incorporated by reference herein.
The electric segment has generated an average of 61% of its energy
requirements over the past three years while purchasing the remainder through
firm contracts and spot market purchases. The following table shows the overall
fuel and purchased power mix for the past three years:
<TABLE>
<CAPTION>
Source 1994 1993 1992
------ ---- ---- ----
<S> <C> <C> <C>
Coal 44.7% 41.0% 42.5%
Purchased Power 36.1 40.8 40.2
Hydro 13.5 14.0 15.2
Gas & Oil 5.7 4.2 2.1
---- ---- ----
100.0% 100.0% 100.0%
------ ------ ------
------ ------ ------
</TABLE>
A divisional summary of generation capability, firm purchased power
contracts and cost of energy is set forth in Exhibit 99(a) to this Annual Report
on Form 10-K and is incorporated by reference herein.
In late 1992 and early 1993, the company renegotiated its major coal supply
and rail contracts, all at favorable prices. These contracts supply a
substantial portion of the company's coal requirements. The company also
purchases coal in the spot market when market conditions dictate.
3
<PAGE>
A summary of the electric operations is set forth on pages 20 and 21 of the
company's 1994 Annual Report to Shareholders. Such information is incorporated
by reference herein.
COMPETITION
See page 21 of the company's Annual Report to Shareholders incorporated by
reference herein for a discussion regarding competition.
GAS OPERATIONS
The company serves approximately 779,630 customers in eight states through
its Peoples Natural Gas ("PNG"), Michigan Gas Utilities ("MGU"), Northern
Minnesota Utilities ("NMU"), Kansas Public Service ("KPS"), WVP and MPS
divisions.
Residential sales have accounted for approximately 58%, 55% and 54% of gas
revenues during 1994, 1993 and 1992, respectively, and approximately 55%, 51%
and 50% of thousand cubic feet ("MCF") tariff gas volumes sold during 1994, 1993
and 1992, respectively. Gas volumes delivered for third parties have averaged
approximately 48% of total MCF deliveries over the past three years due
primarily to the deregulation within the natural gas industry. A summary of the
company's gas revenues, MCF sales and customers, by class, for the past three
years is set forth under "Gas Operations" on page 22 of the company's 1994
Annual Report to Shareholders. Such information is incorporated by reference
herein.
In 1994, the company's gas divisions purchased approximately 43% of their
gas supply requirements through spot market purchases. A divisional summary of
information on contract and spot market purchases and gas costs is set forth in
Exhibit 99(b) to this Annual Report on Form 10-K, and is incorporated by
reference herein.
RECENT ACQUISITIONS
On February 1, 1993, the company purchased the Nebraska gas distribution
system of NorAm Energy Corp. (formerly Arkla, Inc.) for approximately
$106 million, including $21 million in working capital. The Nebraska System
serves about 124,000 gas customers.
On September 30, 1994, the company purchased the Kansas gas distribution
system and selected pipeline properties from NorAm Energy Corp. for
approximately $23.0 million. The Kansas system serves approximately 22,000
customers.
On January 5, 1995, the company purchased a Missouri intrastate natural gas
pipeline system from Edisto Resources Corporation. The $75 million purchase
price includes the gas distribution system at Fort Leonard Wood, Missouri and a
pipeline that crosses the Mississippi river north of St. Louis.
A summary of the gas operations is set forth on pages 22 and 23 of the
company's 1994 Annual Report to Shareholders. Such information is incorporated
by reference herein.
COMPETITION
The company's gas divisions are subject to competition in the industrial
sector from fuel oil, propane, coal and waste wood. The company has been able
to maintain its customer base through flexible tariff rates, attractive storage
pricing and transportation services. The company believes it can continue to
retain industrial customers through such mechanisms in the future.
Residential customer competition comes primarily from electric utility
incentives and low-cost financing offers. The company has been able to maintain
its customer base through similar programs of its own.
4
<PAGE>
ENERGY RELATED BUSINESSES
Aquila formed three business units in 1989 to focus on various segments of
its operations: Aquila Energy Marketing Corporation, Aquila Energy Resources
Corporation and Aquila Gas Pipeline Corporation (formerly Aquila Gas Systems
Corporation). In October 1993, Aquila Gas Pipeline Corporation (AGP) sold, in
an initial public offering, 5.4 million shares of common stock, representing
about 18% of the outstanding stock of AGP.
Aquila Energy Marketing Corporation (AEM) has a marketing, supply and
transportation network consisting of relationships with more than 1,000 gas
producers and 500 local distribution companies and end-users throughout the
United States, Mexico and Canada. Through more than 350 transportation
agreements, it has over 17,500 gas receiving and delivery points available on a
network of 33 pipelines.
Aquila Energy Resources Corporation (AER) acquires proven gas and oil
reserves and operates onshore and offshore production facilities. Supplementary
information on gas and oil-producing activities appears in Note 13 on pages 48
and 49 of the company's 1994 Annual Report to Shareholders. Such information is
incorporated by reference herein.
AGP owns and operates a 2,700-mile intrastate gas transmission and
gathering network and four processing plants that extract and sell natural gas
liquids and markets natural gas.
AER's net gas and oil production, average gross sales price per MCF of gas
and per barrel of oil, and average production costs of gas and oil stated on an
MCF equivalent basis are reflected below:
<TABLE>
<CAPTION>
Production(1) Average Gross
--------------- Sales Price
Gas Oil ----------- Average Production
Year (MCF) (Bbls.) Per MCF Per Bbl. Costs per MCFe(2)
---- ----- ------- ------- -------- -----------------
<S> <C> <C> <C> <C> <C>
1994 21,731 907 $2.53 $17.47 $.60
1993 23,291 1,070 $2.38 $18.12 $.59
1992 24,110 1,444 $1.68 $19.78 $.58
<FN>
(1) Production volumes are in thousands.
(2) Oil production is converted into MCF equivalents at a rate of six MCF per
barrel, representing the approximate relative energy content of oil and
natural gas.
</TABLE>
AEM has entered into numerous long-term gas supply contracts at fixed
prices. At December 31, 1994, AEM had minimum fixed price sales obligations of
20.7, 15.2, 15.2, 15.2 and 15.2 BCF for deliveries in the year 1995 to 1999,
respectively, at prices that range from $1.60 to $3.50 per MCF.
In 1993, Aquila implemented a new business strategy and recorded a $69.8
million charge against income ($45 million after tax) for disposal of selected
gas sales contracts, impairment of certain offshore assets, and other
restructuring costs. See Note 2 on page 38 in the Annual Report to Shareholders
for more information. In 1992, the company and Aquila filed a lawsuit against
two former officers of AER, as well as the wife of one of them, seeking to
recover actual and punitive damages for improper payments related to the
acquisition of gas and oil reserves. See page 13 for more information.
COMPETITION
Aquila has many competitors in the markets it serves, including other
marketing companies, gas pipelines, distribution companies, major oil and gas
companies and alternative fuels. Aquila's ability to compete successfully and
grow in this environment is contingent upon performance, price and the stability
of the gas markets.
The competition Aquila encounters in acquiring assets typically comes from
pipeline and production companies. The primary focus of all groups is to find
strategically located reserves to support their individual markets.
5
<PAGE>
REGULATION
The following table summarizes the regulatory jurisdictions under which
each of the Company's regulated businesses operates.
Division Jurisdiction
-------- ------------
Kansas Public Service Kansas Corporation Commission
Michigan Gas Utilities Michigan Public Service Commission
Missouri Public Service Public Service Commission of the State of
Missouri
Federal Energy Regulatory Commission
Northern Minnesota Utilities Minnesota Public Utilities Commission
Peoples Natural Gas Minnesota Public Utilities Commission
Iowa State Utilities Board
Kansas Corporation Commission
Public Utilities Commission of the State of
Colorado
West Kootenay Power, Ltd. British Columbia Utilities Commission
West Virginia Power Public Service Commission of West Virginia
WestPlains Energy Kansas Corporation Commission
Public Utilities Commission of the State of
Colorado
Federal Energy Regulatory Commission
There is no state regulatory body in Nebraska which has jurisdiction over
utility operations. However, in Nebraska, municipalities which are served by
PNG regulate rates and services therein.
AGP's pipeline volumes and rates are regulated by the Texas Railroad
Commission.
ENVIRONMENTAL
The company is regulated by certain local, state and federal agencies in
the United States and by provincial and federal agencies in Canada. The company
is subject to various environmental regulations including air quality standards
and emission limitations, clean water criteria pertaining to certain facilities
and the handling and disposal of hazardous substances. Compliance with existing
regulations, and those which may be promulgated in the future, can result in
considerable capital expenditures and operation and maintenance expense. A
further discussion of environmental matters is set forth in Note 10 under
"Environmental" on page 45 of the company's 1994 Annual Report to Shareholders.
Such information is incorporated by reference herein.
Executive Officers of the Company
---------------------------------
Richard C. Green, Jr. Chairman of the Board of Directors, President and
Chief Executive Officer. Age 40. Chairman of the
Board of Directors since February 1989 and President
and Chief Executive Officer since May 1985.
John R. Baker Vice Chairman of the Board of Directors. Age 68.
Present position three years. Prior position was
Senior Vice President, Corporate Development for six
years.
Robert K. Green Managing Executive Vice President. Age 33. Present
position since May 1993. Previously Executive Vice
President for four months. Prior executive
positions at the company's Missouri Public Service
division, beginning in 1988, included two years as
President.
6
<PAGE>
Joseph J. Colosimo Managing Senior Vice President. Age 44. Present
position since May 1993. Previously Vice
President, Human Resources since 1991. Prior
positions include Corporate Director, Human
Resources & Ethics, Loral Aerospace, 1990 - 1991;
Director, Personnel & Organization, Ford Aerospace,
1988 - 1990.
Robert L. Howell Managing Senior Vice President. Age 54. Present
position since May 1993. Previously Vice President,
Corporate Development since 1988.
Albert J. Budney, Jr. Managing Vice President, Power Services. Age 47.
Present position since September, 1994. Previously
President, Missouri Public Service, 1993-94. Prior to
being employed by the company, Mr. Budney was Vice
President, Stone & Webster Engineering Corporation,
1991-92, Vice President, Stone & Webster Management
Consultants, 1990-91. General Manager, Strategic
Planning, Budgeting and Financial Analysis, Public
Service Electric and Gas Company 1988-90.
B. C. Burgess Managing Vice President, Marketing Services. Age 49.
Present position since September, 1994. Mr. Burgess was
employed as a Vice President from January, 1994. Prior
to being employed by the company, Mr. Burgess was Vice
President, Information Services, Bell Atlantic
Corporation, 1993 and Vice President, Marketing-Business
Services, 1991-1993 and Vice President, Corporate Market
Planning, 1990-1991 with Sprint Corporation.
Charles K. Dempster Managing Vice President, Energy Resources. Age 52.
Present position since September, 1994. Also serves as
President of Aquila Energy, a position held since
January 1993. Prior to being employed by the company,
Mr. Dempster was President of Reliance Pipeline Company
since 1987.
James G. Miller Managing Vice President, Energy Delivery. Age 46.
Present position since September, 1994. President,
WestPlains Energy, 1991-94. President, Michigan Gas
Utilities, 1983-91.
William D. Bandt Vice President. Age 47. Present position since April,
1994. Prior to being employed by the company, Mr. Bandt
was Managing Director, Hale Investments since 1988.
James S. Brook Vice President. Age 44. Present position effective
November 1993. Prior position was Senior Vice President
of the Company's Missouri Public Service division for
four years. Mr. Brook also held several positions at
West Kootenay Power, including Treasurer and Chief
Financial Officer from 1980 - 1982 and Vice President
-Finance from 1982 - 1990.
Michael D. Bruhn Vice President. Age 40. Present position effective
February 1994. Prior position was Director - Corporate
Development for the Company since 1991. Prior to
joining the Company, Mr. Bruhn held the position of
Senior Vice President - Corporate Finance at B.C.
Christopher Securities Co. for four years and Vice
President - Corporate Finance at George K. Baum & Co.
for over three years.
Philip A. Daddona Vice President. Age 52. Present position since April,
1994. Prior to being employed by the company,
Mr. Daddona was with International Business Machines
Corporation as Corporate Director, Information and
Telecommunication systems from 1992 to 1993 and General
Manager, Headquarters Information and Telecommunications
Region from 1988 to 1992.
7
<PAGE>
Jon R. Empson Vice President. Age 50. Present position since 1993.
Prior to current position, Mr. Empson was Senior Vice
President, Administration for Peoples Natural Gas from
1988.
Sally C. McElwreath Vice President. Age 54. Present position since
October, 1994. Prior to being employed by the company,
Ms. McElwreath was Vice President, Corporate
Communication for Macmillan, Inc. from 1991 to 1993 and
was General Manager, Corporate Communications for
Official Airline Guides from 1990 to 1991. From
1988 to 1990, Ms. McElwreath owned her own company.
Leo E. Morton Vice President. Age 49. Present position since
February 1994. Prior to being employed by the company,
Mr. Morton was Vice President, AT&T Microelectronics
from 1988.
Judith A. Samayoa Vice President. Age 42. Present position since
September 1993. Previously Vice President, Accounting
since 1987.
Dale J. Wolf Vice President, Treasurer and Corporate Secretary. Age
55. Present position five years. Prior position was
Vice President, Finance and Treasurer for four years.
All officers are elected annually by the Board of Directors for a term of
one year. Robert K. Green is the brother of Richard C. Green, Jr., and Avis G.
Tucker, Director, is the aunt of Richard C. Green, Jr. and Robert K. Green.
8
<PAGE>
ITEM 2. PROPERTIES
The company owns, through its divisions and Canadian subsidiary, electric
production, transmission and distribution systems and gas transmission and
distribution systems throughout its service territory. The company owns,
through Aquila, proven natural gas and oil reserves and gas gathering,
processing and pipeline systems.
Substantially all of MGU's utility plant is mortgaged under terms pursuant
to an Indenture of Mortgage and Deed of Trust dated July 1, 1951, as
supplemented (the "MGU Indenture"). Substantially all of the Company's WKP
subsidiary's utility plant is mortgaged under terms pursuant to a separate
indenture.
UTILITY FACILITIES
The company's electric production facilities, as of December 31, 1994, are
as follows:
<TABLE>
<CAPTION>
Unit
Year Capability
Unit Location Installed (KW Net) Fuel
---- -------- --------- ---------- ----
<S> <C> <C> <C> <C>
MPS
---
Sibley #1 Sibley, Missouri 1960 52,400 Coal
Sibley #2 Sibley, Missouri 1962 52,400 Coal
Sibley #3 Sibley, Missouri 1969 387,900 Coal
Jeffrey #1 Pottawatomie County, Kansas 1978 55,800 Coal
Jeffrey #2 Pottawatomie County, Kansas 1980 53,900 Coal
Jeffrey #3 Pottawatomie County, Kansas 1983 56,000 Coal
Ralph Green #3 Pleasant Hill, Missouri 1981 60,100 Gas
Nevada #1 Nevada, Missouri 1974 18,600 Oil
Greenwood #1 Greenwood, Missouri 1975 46,100 Oil
Greenwood #2 Greenwood, Missouri 1975 44,200 Oil
Greenwood #3 Greenwood, Missouri 1977 47,200 Oil
Greenwood #4 Greenwood, Missouri 1979 45,700 Oil
KCI Platte County, Missouri 1970 23,700 Gas
WPE
---
Judson Large #4 Dodge City, Kansas 1969 142,750 Gas/Oil
Arthur Mullergren #3 Great Bend, Kansas 1963 94,550 Gas/Oil
Cimarron River #1 Liberal, Kansas 1963 58,000 Gas
Cimarron River #2 Liberal, Kansas 1967 14,000 Gas
Clifton #1 Clifton, Kansas 1974 71,000 Gas
Clifton #2 Clifton, Kansas 1974 2,500 Oil
Jeffrey #1 Pottawatomie County, Kansas 1978 55,800 Coal
Jeffrey #2 Pottawatomie County, Kansas 1980 53,900 Coal
Jeffrey #3 Pottawatomie County, Kansas 1983 56,000 Coal
W.N. Clark #1 Canon City, Colorado 1955 17,250 Coal
W.N. Clark #2 Canon City, Colorado 1959 23,750 Coal
Pueblo #6 Pueblo, Colorado 1949 19,500 Gas/Oil
Diesel #'s 1,2,3,4,5 Pueblo, Colorado 1964 10,000 Oil
Diesel #'s 1,2,3,4,5 Rocky Ford, Colorado 1964 10,000 Oil
WKP
---
No. 1 Lower Bonnington, British Columbia 1925 41,400 Hydro
No. 2 Upper Bonnington, British Columbia 1907/1916/1940 59,400 Hydro
No. 3 South Slocan, British Columbia 1928 53,200 Hydro
No. 4 Corra Linn, British Columbia 1932 51,300 Hydro
---------
TOTAL 1,778,300
---------
---------
</TABLE>
9
<PAGE>
At December 31, 1994, the company owned substations aggregating 9,393,434
KVA, 5,346 miles of transmission line ranging from 34,500 volt to 345,000 volt,
16,138 miles of overhead distribution line and 2,396 miles of underground
distribution line.
At December 31, 1994, the company's gas operations had 2,951 miles of gas
gathering and transmission pipelines and 19,963 miles of distribution mains and
services located throughout its divisional service territories.
AQUILA ENERGY CORPORATION PROPERTIES
Supplementary information on gas and oil producing activities of Aquila and
non-regulated operations of a utility division is set forth under "Reserve
Quantity Information (Unaudited)" on pages 48 and 49 of the company's 1994
Annual Report to Shareholders. Such information is incorporated by reference
herein.
The number of productive gas and oil wells in which Aquila has an interest
at December 31, 1994 is reflected below:
<TABLE>
<CAPTION>
Gross Net
----- ---
<S> <C> <C>
Natural Gas 315 92
Oil 117 34
--- ---
Total 432 126
--- ---
--- ---
</TABLE>
The following table sets forth the gross and net, developed and undeveloped
acreage in which Aquila has an interest as of December 31, 1994:
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage
--------------- ---------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
New Mexico 320 112 5,357 1,221
Oklahoma 63,037 38,735 34,967 15,221
Louisiana-offshore 88,293 52,803 15,603 4,922
Louisiana-onshore 6,333 5,020 4,159 2,855
Texas-offshore 21,600 14,760 -- --
Texas-onshore 5,643 3,671 4,208 2,047
------- ------- ------- -------
Total 185,226 115,101 64,294 26,266
------- ------- ------- -------
------- ------- ------- -------
</TABLE>
Aquila drilled 20 gross (8.1 net) exploratory wells during 1994 of which 17
gross (7.1 net) went dry. It drilled 1 gross (.3 net) well in 1993 and no
wells in 1992. The number of development wells completed and wells acquired
during 1994, 1993 and 1992 follows:
10
<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Wells Completed:
Natural gas 27 11.4 14 5.6 2 1.4
Oil 2 .8 2 .5 6 1.5
Dry holes 11 7.9 6 2.2 -- --
---- ---- ---- ---- ---- ----
Total 40 20.1 22 8.3 8 2.9
---- ---- ---- ---- ---- ---
---- ---- ---- ---- ---- ---
Wells Acquired
(Sold), net:
Natural gas 13 4.4 (56) .8 -- .6
Oil 5 1.0 2 1.7 -- .9
---- ---- ---- ---- ---- ---
Total 18 5.4 (54) 2.5 -- 1.5
---- ---- ---- ---- ---- ---
---- ---- ---- ---- ---- ---
</TABLE>
At December 31, 1994, Aquila had 13 gross (4.2 net) wells in the process of
being drilled. The company abandoned 7 gross and 7 net wells in 1994.
AGP has 10 natural gas pipeline systems having an aggregate length of
approximately 2,718 miles and 67 compressor stations having approximately 84,259
horsepower. These pipelines do not form an interconnected system. Set forth
below is information with respect to AGP's pipeline systems as of December 31,
1994:
<TABLE>
<CAPTION>
Average
Gas Throughput Daily Gas
Year Placed in Miles of Capacity Throughput
Gathering Systems Service Location Pipeline (1) (MCF)(1) (MCF)(2)
----------------- -------------- -------- ------------ ------------- ----------
<S> <C> <C> <C> <C> <C>
Southeast Texas
Pipeline System
(SETPS) 1980 Southeast Texas 1,865 360 316
Mentone 1976 West Texas 13 60 --
Gomez 1970 West Texas 11 40 1
Menard County 1983 West Texas 118 30 7
Maverick County 1978 West Texas 118 20 3
Rhoda Walker 1977 West Texas 30 20 5
Panola County 1981 East Texas 24 8 1
Elk City 1985 Southwest Oklahoma 142 115 67
Mooreland 1974 Northwest Oklahoma 304 40 20
Brooks-Hidalgo 1993 South Texas 93 75 14
--- --- ---
434
Fuel and Shrinkage (63)
---
Total 2,718 768 371
----- --- ---
----- --- ---
<FN>
(1) All capacity, volume and mileage information is approximate. Capacity
figures are management's estimates based on existing facilities without
regard to the present availability of natural gas.
(2) Excludes off-system sales with average daily volumes of 129 MCF from other
companies' facilities.
</TABLE>
AGP owns and operates four natural gas processing and treating plants with
aggregate gas throughput capacity of 373,000 MCF. Set forth below is
information with respect to AGP's processing plants as of December 31, 1994.
11
<PAGE>
<TABLE>
<CAPTION>
Year Placed in Gas Throughput Natural Gas Liquid Associated
Plant Service Capacity * Gas Throughput * Production * Gathering System
----- -------------- -------------- ---------------- ------------------ ----------------
<S> <C> <C> <C> <C> <C>
La Grange, Texas 1981 230,000 207,000 24.9 SETPS
Somerville, Texas 1993 25,000 26,000 3.3 SETPS
Nopal, Texas 1992 3,000 -- -- SETPS
Elk City,
Oklahoma 1985 115,000 65,000 2.8 Elk City
------- ------- ----
Total 373,000 298,000 31.0
------- ------- ----
------- ------- ----
<FN>
* Gas throughput is in MCF and natural gas liquid is in millions of gallons.
</TABLE>
The availability of natural gas reserves to AGP depends on their
development in the area served by its pipelines and on AGP's ability to purchase
gas currently sold to or transported through other pipelines. The development
of additional gas reserves will be affected by many factors including the prices
of natural gas and crude oil, exploration and development costs and the presence
of natural gas reserves in the areas served by AGP's systems.
Additional information regarding Aquila's property and other non-regulated
property is set forth in Note 4 on page 39 of the company's 1994 Annual Report
to Shareholders. Such information is incorporated by reference herein.
OTHER PROPERTIES
Information regarding the company's UtilCo Group subsidiary's generating
projects is set forth in Exhibit 99(c) to this Annual Report on Form 10-K and
incorporated by reference herein.
12
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
On June 17, 1992, a class action suit was filed in the United States
District Court for the Western District of Missouri by a stockholder against the
Company and certain unnamed employees of the Company and/or its subsidiary,
Aquila Energy Corporation. Plaintiff subsequently dismissed its claims against
all defendants except the Company. The case caption is WILLIAM ALPERN VS.
UTILICORP UNITED INC.. In this case, plaintiff alleges that the Company
violated various securities laws, including Section 10(b) of the Securities
Exchange Act of 1934, as amended, and Rule 10b-5 of the Securities and Exchange
Commission, both by making misrepresentations and omitting to state material
facts in connection with public disclosures. Plaintiff also alleges a claim
under Section 11 of the Securities Act of 1933, as amended. Among other relief,
plaintiff seeks unspecified compensatory damages. The District Court has
dismissed the case by granting summary judgment to UtiliCorp. The plaintiffs
have asked the District Court to reconsider that decision and they have appealed
that decision to the United States Court of Appeals for the Eighth Circuit.
The lawsuit UTILICORP ET AL. V. STEGALL ET AL, which has previously been
reported on in the company's Forms 10-Q for the quarters ended March 31, 1994,
and June 30, 1994, has now been resolved just prior to its scheduled trial
setting of October 24, 1994. In August and September, the plaintiffs, UtiliCorp
and Aquila Energy Resources Corporation, reached settlements with several minor
defendants. On October 6, the plaintiffs concluded a settlement with one of the
major defendants which provides for payment of $4,310,000 to plaintiffs. On
October 18, the Court granted plaintiffs summary judgment on the remaining
defendants, in which all counterclaims and third-party claims of defendants are
to be dismissed and agreed upon judgments are to be entered for plaintiffs
against these defendants. The company believes that, due to the financial
condition of these defendants, any substantial recovery upon these judgments is
remote.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No such matters were submitted during the fourth quarter of 1994.
13
<PAGE>
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The company's common stock is listed on the New York, Pacific and Toronto
stock exchanges under the symbol UCU. At December 31, 1994, the company had
37,255 common shareholders of record. Information relating to market prices of
Common Stock and cash dividends on Common Stock is set forth in Note 14 on page
50 of the company's 1994 Annual Report to Shareholders. Such information is
incorporated by reference herein.
Cash dividends on the Common Stock of the company and its predecessor have
been paid each year since 1939.
Cash dividends on and acquisition of the company's capital stock are
restricted by provisions of the MGU Indenture and by the Preference Stock
provisions of the Certificate of Incorporation. Under the most restrictive of
these provisions, contained in the MGU Indenture, the company may not declare or
pay any dividend (other than a dividend payable in shares of its capital stock),
whether in cash, stock or otherwise, or make any other distribution, on or with
respect to any class of its capital stock, or purchase or otherwise acquire any
shares of, any class of its capital stock if, after giving effect thereto, the
sum of (i) the aggregate amount of all dividends declared and all other
distributions made (other than dividends declared or distributions made in
shares of its capital stock) on shares of its capital stock, of any class,
subsequent to December 31, 1984, plus (ii) the excess, if any, of the amount
applied to or set apart for the purchase or other acquisition of any shares of
its capital stock, of any class, subsequent to December 31, 1984, over such
amounts as shall have been received by the company as the net cash proceeds of
sales of shares of its capital stock, of any class, subsequent to December 31,
1984, would exceed the sum of the net income of the company since January 1,
1985, plus $50 million. In addition, the company may not declare such dividends
unless it maintains a tangible net worth of at least $250 million and the
aggregate principal amount of its outstanding indebtedness does not exceed 70%
of its capitalization. None of the company's retained earnings was restricted
as to payment of cash dividends on its capital stock as of December 31, 1994.
ITEM 6. SELECTED FINANCIAL DATA
Information regarding the five-year selected financial data is set forth on
pages 52 and 53 of the company's 1994 Annual Report to Shareholders. Such
information is incorporated by reference herein. Information regarding the
restructuring charge and gain on sale of subsidiary stock can be found in Note 2
on page 38 of the company's 1994 Annual Report to Shareholders. Such
information is incorporated by reference herein. Information concerning utility
and energy related acquisitions and non-regulated property and investments
appears in Note 3 and Note 4, respectively, on pages 38 and 39 of the company's
1994 Annual Report to Shareholders. Such information is incorporated by
reference herein. Information related to the company's capitalization is set
forth under "Consolidated Statement of Capitalization" on page 34 of the
company's 1994 Annual Report to Shareholders. Such information is incorporated
by reference herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Management's discussion and analysis of financial condition and results of
operations can be found under "Operations and Finance" on pages 19 through 30 of
the company's 1994 Annual Report to Shareholders. Such information is
incorporated by reference herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements, together with the report thereon of Arthur
Andersen LLP dated January 31, 1995, are set forth on pages 32 through 51 of the
company's 1994 Annual Report to Shareholders.
14
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEMS 10, 11, 12 AND 13. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY,
EXECUTIVE COMPENSATION, SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT, AND CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding these items appears in the company's definitive proxy
statement for its annual meeting of shareholders to be held May 3, 1995 and is
hereby incorporated by reference in this Annual Report on Form 10-K, pursuant to
General Instruction G(3) of Form 10-K. For information with respect to the
executive officers of the company, see "Executive Officers of the Company"
following Item 1 in Part I.
15
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
Page(s)
-------
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Consolidated Statements of Income for the
three years ended December 31, 1994....................... *32
Consolidated Balance Sheets at December 31,
1994, 1993, and 1992...................................... *33
Consolidated Statements of Capitalization at
December 31, 1994, 1993, and 1992......................... *34
Consolidated Statements of Common Share-
holders' Equity for the three years ended
December 31, 1994......................................... *34
Consolidated Statements of Cash Flows
for the three years ended December 31, 1994............... *35
Notes to Consolidated Financial Statements................. *36-50
Report of Arthur Andersen LLP.............................. *51
*Incorporated by reference from the indicated pages of the 1994 Annual
Report to Shareholders.
(2) Financial Statement Schedule:
Report of Independent Accountant on Financial
Statement Schedule 17
II Valuation and Qualifying Accounts for the years
1994, 1993 and 1992 18
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
(3) List of Exhibits:
Incorporated herein by reference to the Index to Exhibits.
The following exhibits relate to a management contract or compensatory plan
or arrangement:
10(a)(2) UtiliCorp United Inc. Deferred Income Plan.
10(a)(3) UtiliCorp United Inc. 1986 Stock Incentive Plan.
10(a)(4) UtiliCorp United Inc. Annual and Long-Term Incentive Plan.
10(a)(5) UtiliCorp United Inc. 1990 Non-Employee Director Stock Plan.
10(a)(6) Supplemental Executive Retirement Agreement dated October 13,
1988, between the company and Dale J. Wolf.
10(a)(7) Severance Compensation Agreement dated as of May 3, 1989, between
the company and each Executive of the Company.
10(a)(8) Executive Severance Payment Agreement.
10(a)(9) Temporary Contract Employee Agreement.
10(a)(10) Split Dollar Agreement.
10(a)(11) Supplemental Retirement Agreement.
(b) Reports on Form 8-K.
None
16
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements for 1994, 1993 and 1992 described on page 51
of UtiliCorp United Inc.'s Annual Report to the Board of Directors and
Shareholders incorporated by reference in this Form 10-K, and have issued our
report thereon dated January 31, 1995. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The Financial
Statements Schedule listed in Item 14(a)2 is presented for the purposes of
complying with the Securities and Exchange Commission's rules and is not part 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 31, 1995
CONSENT OF INDEPENDENT ACCOUNTANTS
As Independent Public Accountants we hereby consent to the incorporation by
reference in the Prospectuses constituting part of the Registration Statements
on Form S-3 (No. 33-16990, No. 33-47289, and No. 33-39466) and on Form S-8
(No. 33-45525, No. 33-50260, No. 33-45074 and No. 33-52094) of UtiliCorp
United Inc. of our report dated January 31, 1995 appearing on page 51 of the
1994 Annual Report to the Board of Directors and Shareholders which is
incorporated in this Annual Report on Form 10-K. We also consent to the
incorporation by reference of our report on the Financial Statement Schedule,
which appears above. It should be noted that we have not audited any financial
statements of UtiliCorp United Inc. subsequent to December 31, 1994 or
performed any audit procedures subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Kansas City, Missouri
March 14, 1995
17
<PAGE>
UTILICORP UNITED INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(In millions)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E Column F
------------------------------------- ---------- ----------- ---------- ------------- -----------
Deductions
from Reserves
Beginning Additions for Purposes Ending
Balance Purchase of Charged To for Which Balance
Description December 31 Division Expense Created December 31
------------------------------------- ----------- ----------- ---------- ------------- -----------
<S> <C> <C> <C> <C> <C>
1994 Allowance for Doubtful Accounts $4.2 -- 4.6 7.0 $1.8
1993 Allowance for Doubtful Accounts $2.6 .3 5.4 4.1 $4.2
1992 Allowance for Doubtful Accounts $1.4 -- 2.8 1.6 $2.6
</TABLE>
18
<PAGE>
Index to Exhibits
-----------------
*3(a)(1) Certificate of Incorporation of the Company. (Exhibit 3(a)(1) to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1991.)
*3(a)(2) Certificate of Amendment to Certificate of Incorporation of the
Company. (Exhibit 4(a)(1) to Registration Statement No. 33-16990
filed September 3, 1987.)
*3(a)(3) Certificate of Designation of the Preference Stock (Cumulative),
$2.05 Series. (Exhibit 3(a)(4) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1991.)
*3(a)(4) By-laws of the Company as amended. (Exhibit 3 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1993.)
*4(a)(1) Certificate of Incorporation of the Company. (Exhibit 4(a)(1) to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1991.)
*4(a)(2) Certificate of Amendment to Certificate of Incorporation of the
Company. (Exhibit 4(a)(1) to Registration Statement No. 33-16990
filed September 3, 1987.)
*4(a)(3) Certificate of Designation of the Preference Stock (Cumulative),
$2.05 Series. (Exhibit 4(a)(4) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1991.)
*4(a)(4) By-laws of the Company as amended. (Exhibit 3 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1993.)
*4(b)(1) Indenture, dated as of November 1, 1990, between the Company and
The First National Bank of Chicago, Trustee. (Exhibit 4(a) to
the Company's Current Report on Form 8-K, dated November 30,
1990.)
*4(b)(2) First Supplemental Indenture, dated as of November 27, 1990.
(Exhibit 4(b) to the Company's Current Report on Form 8-K, dated
November 30, 1990.)
*4(b)(3) Second Supplemental Indenture, dated as of November 15, 1991.
(Exhibit 4(a) to UtiliCorp United Inc.'s Current Report on
Form 8-K dated December 19, 1991.)
*4(b)(4) Third Supplemental Indenture, dated as of January 15, 1992.
(Exhibit 4(c)(4) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1991.)
*4(b)(5) Fourth Supplemental Indenture, dated as of February 24, 1993.
(Exhibit 4(c)(5) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1992.)
*4(b)(6) Fifth Supplemental Indenture, dated as of April 1, 1993.
(Exhibit 4(c)(6) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993.)
*4(b)(7) Sixth Supplemental Indenture, dated as of November 1, 1994.
(Exhibit 4(d)(7) to the Company's Registration Statement on Form
S-3 No. 33-57167, filed January 4, 1995.)
*4(c) Twentieth Supplemental Indenture, dated as of May 26, 1989,
Supplement to Indenture of Mortgage and Deed of Trust, dated
July 1, 1951. (Exhibit 4(d) to Registration Statement
No. 33-45382, filed January 30, 1992.)
Long-Term debt instruments of the Company in amounts not
exceeding 10 percent of the total assets of the Company and its
subsidiaries on a consolidated basis will be furnished to the
Commission upon request.
19
<PAGE>
*10(a)(1) Agreement for the Construction and Ownership of Jeffrey Energy
Center, dated as of January 13, 1975, among Missouri Public
Service Company, The Kansas Power and Light Company, Kansas Gas
and Electric Company and Central Telephone & Utilities
Corporation. (Exhibit 5(e)(1) to Registration Statement
No. 2-54964, filed November 7, 1975.)
*10(a)(2) UtiliCorp United Inc. Deferred Income Plan. (Exhibit 10(a)(2) to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1991.)
*10(a)(3) UtiliCorp United Inc. 1986 Stock Incentive Plan. (Exhibit
10(a)(3) to the Company's Annual Report on Form 10-K for the year
ended December 31, 1991.)
10(a)(4) UtiliCorp United Inc. Annual and Long-Term Incentive Plan.
*10(a)(5) UtiliCorp United Inc. 1990 Non-Employee Director Stock Plan.
(Exhibit 10(a)(5) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1991.)
*10(a)(6) Supplemental Executive Retirement Agreement dated October 13,
1988, between the Company and Dale J. Wolf. (Exhibit 10(a)(10)
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1989.)
*10(a)(7) Severance Compensation Agreement dated as of May 3, 1989, between
the Company and each Executive of the Company. (Exhibit
10(a)(13) to the Company's Annual Report on Form 10-K for the
year ended December 31, 1990.)
*10(a)(8) Executive Severance Payment Agreement (Exhibit 10 to the
Company's Quarterly Report on Form 10-Q filed for the quarter
ended September 30, 1993.)
*10(a)(9) Temporary Contract Employee Agreement. (Exhibit 10(a)(10) to the
Company's Annual Report on Form 10-K for the year ended December
31, 1993.)
10(a)(10) Split Dollar Agreement dated as of June 12, 1985, between the
Company and James G. Miller.
10(a)(11) Supplemental Retirement Agreement dated as of January 27, 1983,
between the Company and James G. Miller.
*10(a)(12) Lease Agreement dated as of August 15, 1991, between Wilmington
Trust Company, as Lessor, and the Company, as Lessee. (Exhibit
10(a)(13) to the Company's Annual Report on Form 10-K for the
year ended December 31, 1991.)
*10(a)(13) Credit Agreement dated as of December 13, 1993 among the Company
as Borrower, the Banks Named Therein as Banks, and Citibank,
N.A., as Agent [Three-Year Facility]. (Exhibit 10(a)(12) to the
Company's Annual Report on Form 10-K for the year ended December
31, 1993.)
10(a)(14) Letter Amendment dated as of December 8, 1994 [Three-year
Facility].
*10(a)(15) Credit Agreement dated as of December 13, 1993 among the Company
as Borrower, the Banks Named Therein as Banks, and Citibank,
N.A., as Agent [360-Day Facility]. (Exhibit 10(a)(13) to the
Company's Annual Report on Form 10-K for the year ended December
31, 1993.)
10(a)(16) Letter Amendment dated as of December 8, 1994 [360-Day Facility].
11 Statement regarding Computation of Per Share Earnings.
20
<PAGE>
<TABLE>
<S> <C>
13 1994 Annual Report to Shareholders.
21 Subsidiaries of the Company.
23 Consent of Arthur Andersen LLP appearing on Page 17 of this
Form 10-K.
27 Financial Data Schedules.
99(a) 1994 Utility Data - Electric Operations.
99(b) 1994 Utility Data - Gas Operations.
99(c) UtilCo Group Generating Projects.
<FN>
___________________
*Exhibits marked with an asterisk are incorporated by reference as indicated pursuant to Rule 12(b)-23.
</TABLE>
21
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UTILICORP UNITED INC.
By: /s/ Richard C. Green, Jr.
------------------------------
Richard C. Green, Jr.
President and Chief Executive Officer
Date: March 14, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons, which include the
Principal Executive Officer, the Principal Financial Officer, the Principal
Accounting Officer and a majority of the Board of Directors, on behalf of the
Company and in the capacities and on the dates indicated.
March 14, 1995 Chairman of the Board of
Directors, President and
Chief Executive Officer
(Principal Executive Officer) /s/ Richard C. Green, Jr.
------------------------------
Richard C. Green, Jr.
March 14, 1995 Vice President and
Corporate Secretary
(Principal Financial Officer) /s/ Dale J. Wolf
------------------------------
Dale J. Wolf
March 14, 1995 Vice President
(Principal Accounting Officer) /s/ James S. Brook
------------------------------
James S. Brook
March 14, 1995 Managing Executive Vice
President and Director /s/ Robert K. Green
------------------------------
Robert K. Green
March 14, 1995 Vice Chairman of the
Board of Directors /s/ John R. Baker
------------------------------
John R. Baker
March 14, 1995 Director /s/ Avis G. Tucker
------------------------------
Avis G. Tucker
March 14, 1995 Director /s/ Robert F. Jackson
------------------------------
Robert F. Jackson
March 14, 1995 Director /s/ Don R. Armacost
------------------------------
Don R. Armacost
22
<PAGE>
March 14, 1995 Director /s/ L. Patton Kline
------------------------------
L. Patton Kline
March 14, 1995 Director /s/ Herman Cain
------------------------------
Herman Cain
March 14, 1995 Director /s/ Stanley O. Ikenberry
------------------------------
Stanley O. Ikenberry
23
<PAGE>
UTILICORP UNITED INC.
ANNUAL AND LONG-TERM INCENTIVE PLAN
INTRODUCTION: The following sets forth the Annual and Long-Term Incentive Plan
for UtiliCorp United Inc. which amends and restates the Annual
Incentive Plan effective January 1, 1986 and expands it to
include the Long-Term Incentive Plan, effective as of January 1,
1994.
(A) PLAN PURPOSES
The key purposes of the Plan are as set forth below.
1. To encourage and reward both annual and long-term sustained
performance above the level of performance that would be expected at a
fully competent level, thereby enabling the Company to continue to
provide outstanding service to its ratepayers and other customers
while enhancing the value of the Company for its stockholders.
2. Further, to provide competitive levels of cash compensation for
key employees to assure the Company of the necessary talent for future
success, and to directly link a significant portion of such
compensation to those performance results most directly impacted by
such key employees.
3. Further, to permit the payment of a significant portion of the
Plan awards on a deferred basis with appropriate vesting requirements
to assist the Company in retaining the services of key employees and,
by using Restricted Stock for such deferral, to enhance the ownership
interest of key employees for the benefit of Company stockholders.
(B) DEFINITIONS
1. "Annual Award" shall mean the payment received annually by a Plan
Participant whether paid in cash or
<PAGE>
shares of Restricted Stock as described in Section (F) below.
2. "Award" shall mean the payment of an Annual Award or Long-Term
Award.
3. "Board" shall mean the Board of Directors of the Company.
4. "Committee" shall mean the Compensation Committee of the Board.
5. "Company" shall mean UtiliCorp United Inc., and its divisions,
subsidiaries and affiliated organizations approved for participation.
6. "Designated Beneficiary" shall mean the person, or persons as
elected by the Participant (or designated by the Company in the
absence of such election) to receive any payments, whether in cash or
shares of Restricted Stock due from the Plan in the event of a
Participant's death.
7. "Discretionary Annual Award" shall have the meaning described in
Section (F), below.
8. "Discretionary Annual Award Pools" shall have the meaning set out
in Section (F), below.
9. "Long-Term Award" shall mean the payment received hereunder,
either in cash and/or shares of Restricted Stock following completion
of a Long-Term Award Cycle.
10. "Long-Term Award Cycle" shall mean a period of three or more
consecutive calendar years during which cumulative Performance Awards
are set.
11. "Effective Date" shall mean January 1, 1994.
12. "Participant" or "Plan Participant" shall mean a key managerial,
professional or technical employee
-2-
<PAGE>
approved for Plan membership by the Board (or the Committee) with
respect to any Plan Year.
13. "Performance Goals" shall have the meaning set forth in
Paragraphs (F) and (H) below.
14. "Plan" shall mean the UtiliCorp United Inc. Annual and Long-Term
Incentive Plan as described herein or amended hereafter.
15. "Plan Year" shall mean January 1 through December 31, the
calendar year, which corresponds with the Company's fiscal year.
16. "Restricted Stock" shall mean shares of the Company's common
stock awarded to Participants under the UtiliCorp United Inc. 1986
Stock Incentive Plan or any successor plan providing for the grant of
Restricted Stock.
(C) PLAN ADMINISTRATION
1. The Company shall be responsible for the general administration
of the Plan.
2. The Board or, at the Board's direction, the Committee shall be
responsible for monitoring the ongoing use of the Plan and shall:
(a) review Company recommendations with respect to all necessary
actions;
(b) review Company recommendations for any amendments to the
Plan; and
(c) approve all Annual Awards and Long-Term Awards under the
Plan and monitor the use of Discretionary Annual Award Pools.
(D) BOARD (OR COMMITTEE) POWERS
-3-
<PAGE>
1. The Board, acting upon the advice and counsel of the Committee,
or the Committee itself if so empowered by the Board, shall have the
following powers with respect to the Plan.
(a) Annual approval of: Participants; opportunity levels; the
basis of Awards; and the method of payment for such Awards
including the use and content of written agreements for
Restricted Stock Awards.
(b) The right to review, amend, and authorize any Performance
Goals or other factors used to determine Annual Awards, Long-Term
Awards and the Discretionary Annual Award Pools for any division
or unit of the Company as described in Section (F) below.
(c) The right to retroactively adjust any aspect of the Plan for
an already completed or ongoing Plan Year if in the Board's (or
Committee's) judgment significant events outside of the control
of Plan Participants have occurred which require such adjustment
if the Plan is to effectively serve its purposes.
(d) The right to receive an annual summary of all Awards paid
for each Plan Year and pertinent information with respect to all
Restricted Stock Awards, plus such other information as it may
reasonably request.
(e) The right to amend or discontinue the Plan at any time if
such action is deemed to be in the best interests of the Company,
its ratepayers and its stockholders. In such event an
appropriate and equitable resolution of Awards in the process of
being earned during a Plan Year shall be made.
(E) PLAN PARTICIPATION
-4-
<PAGE>
1. Each Plan Year all full-time employees shall be eligible to
participate in the Plan with respect to the receipt of Discretionary
Annual Awards pursuant to Section (F) below.
2. With respect to Annual Awards and Long-Term Awards pursuant to
Section (F) below, participation shall be limited to those managerial,
professional, or technical employees who are key employees approved
for participation by the Committee.
3. To the extent separate incentive arrangements are established for
various divisions or units of the Company, participation may include
the eligibility for an Annual Award or Long-Term Award from one or
more of such separate arrangements as the Board (or Committee) may
determine.
4. Participation for an Annual Award or Long-Term Award in one Plan
Year does not automatically qualify an employee for participation in
subsequent years nor does participation in a separate incentive
arrangement for one division or unit automatically qualify an employee
for participation in any other such arrangements.
5. Subject to special action by the Board (or Committee) pursuant to
subsection (6) below, participation for otherwise eligible employees
whose status changes during a Plan Year shall be determined by the
Chief Executive Officer of the Company, in accordance with the
following.
(a) VOLUNTARY TERMINATION OF EMPLOYMENT, OR TERMINATION AT THE
REQUEST OF THE COMPANY. In such event a Participant shall
forfeit all rights to any Award from the Plan for the Plan Year
in which such termination occurs.
(b) DEATH, RETIREMENT, OR TOTAL DISABILITY. In such event a
Participant (or his or her estate)
-5-
<PAGE>
shall be entitled to a pro-rata Award, if any, for the Plan Year
in which such event occurs.
(i) Such Awards shall be determined when all other Awards
are determined for the applicable Plan Year.
(ii) "Pro-rata" shall mean the Award for the entire Plan
Year multiplied by a fraction the numerator of which is the
Participant's days of full-time active employment (counting
any days on short-term disability or salary continuation)
during the Plan Year and denominator of which is 365.
(iii) "Total Disability" shall mean the date of commencement
of payments under the Company's long-term disability plan
applicable to the Participant.
(iv) "Retirement" shall mean the cessation of active
employment and the effective date of normal, later, or early
Retirement under the Company's retirement or pension plan
applicable to the Participant but not a termination of
employment with vested rights under any such plan.
(c) HIRE OR PROMOTION DURING A PLAN YEAR.
Provided such event occurs within the first nine months of any
Plan Year participation may be authorized for a pro-rata Annual
Award or Long-Term Award subject to Board (or Committee) approval
with respect to the opportunity levels and Performance Goals.
Actions taken by the Chief Executive Officer of the Company in
accordance with the above do not require Board (or Committee)
approval.
6. Based upon the recommendation of the Company the Board (or
Committee) may authorize actions other than
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<PAGE>
those set forth in subsection (5) above to address unusual
circumstances.
7. Regardless of any other provision of the Plan a Participant whose
personal, individual, performance for any Plan Year is determined to
be unsatisfactory shall forfeit all rights to an Award for such Plan
Year. This determination shall be made by the Chief Executive Officer
of the Company with respect to employees not assigned to a specific
unit or division and by the chief executive officer of the
Participant's division or unit in all other cases, subject to the
approval of the Chief Executive Officer of the Company.
(F) TYPES OF AWARDS
1. There are three types of Awards payable under the Plan: a Annual
Award, a Long-Term Award and a Discretionary Annual Award.
2. Annual Awards and Long-Term Awards are available only to key
employees specifically approved as eligible for such Awards and
payment with respect thereto shall be based on the achievement of
specific Performance Goals established for each Participant.
(a) Performance Goals may be set for the Company as a whole, for
each division or unit, or for individual performance criteria.
(b) Such Performance Goals can be established on the basis of
specific numeric standards (e.g. return on net assets) or as one
or more objectives or results for which performance achievements
shall be determined on a discretionary, subjective basis by an
appropriate individual, subject to Section (H), below.
(c) For any Plan Year the Annual Award or Long-Term Award for
any Participant shall have a set maximum amount, expressed as a
percentage of annual salary and/or a dollar amount, as approved
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<PAGE>
by the Board (or Committee); and set Award amounts may also be
established at other performance levels such as threshold and par
with or without provision for pro-ration.
(d) Specific Board (or Committee) approval is required annually
for the payment of Awards.
(e) As approved by the Board (or Committee) for any Plan Year
the Annual Award or Long-Term Award payable may be subject to
either or both of the criteria set forth below.
(i) A "STOCKHOLDER (OR CORPORATE) PROTECTION TRIGGER" which
establishes a minimum level of performance, or other action
(e.g. the distribution of a level of dividends), which must
be achieved before any Awards are payable for a Plan Year.
(ii) A "RATEPAYER PROTECTION FEATURE" which establishes a
schedule of absolute or relative performance relating to the
quality or cost of service provided by the Company (or
division or unit) against which actual results will be
compared for the Plan Year with the resulting comparison
used to modify, or eliminate, Total Awards otherwise payable
for such Plan Year.
(f) Each Participant approved for an Award shall receive a
written description of his or her opportunity and applicable
Performance Goals.
3. "Discretionary Awards" are available to any full-time employee of
the Company except the Chief Executive Officer of the Company.
(a) Such Discretionary Awards shall be payable from a
Discretionary Award Pool established annually for each division
or unit and the sum of such Awards for the employees in any unit
or
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<PAGE>
division for any Plan Year cannot exceed the pool approved by the
Board (or Committee) for such division or unit. The pool
established for employees not assigned to a division or unit
shall be used for any Discretionary Award payable to the
respective chief executive officers of the Company's
participating divisions or units. The minimum Discretionary
Award, if any, is $500 and the maximum Discretionary Award is ten
percent of the employee's then existing annual base salary rate.
(b) Discretionary Awards shall be determined subjectively by the
chief executive officer or each division or unit, subject to the
approval of the Chief Executive Officer of the Company and shall
be used to recognize outstanding individual performance, the
accomplishment of a specific task in an exemplary manner, or for
individuals who made an inordinately significant contribution to
overall divisional, unit or Company-wide results.
(c) The total Discretionary Award Pool authorized for any
division or unit need not be spent for any Plan Year.
Unallocated Pool funds are not carried forward for subsequent
Plan Years.
(G) PAYMENT OF AWARDS
1. Discretionary Awards shall be payable in cash.
2. Annual Awards and Long-Term Awards shall be payable in cash,
Restricted Stock, or any combination thereof as approved by the Board
(or Committee) for any individual Participant in any Plan Year;
provided that payment in the form of Restricted Stock shall be
approved by the Committee.
(H) COMPLIANCE WITH SECTION 162(m) REQUIREMENTS.
The Plan shall at all times be administered to ensure that any
Award under the Plan to the
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<PAGE>
Company's Chief Executive Officer and the four highest compensated officers
(determined pursuant to the executive compensation disclosure rules under
the Securities Exchange Act of 1934) (each a "Covered Employee") will be
tax deductible. In furtherance of this goal, with respect to Awards
payable under the Plan for Covered Employees, the Performance Goals
established by the Committee may vary from one Covered Employee to another,
and will be limited to certain business criteria measured by one or more
of the following: revenues, units sold, operating income, operating
company contribution, cash flow, income before taxes, net income, earnings
available per share, return on equity, return on assets, Economic Value
Added (EVA) or total return to stockholders, whether applicable to the
Company or any relevant subsidiary or business unit, or combination
thereof, as the Committee may deem appropriate. The criteria selected by
the Committee shall include a minimum performance standard below which no
payments will be made and a maximum performance level above which no
increased payment will be made. Notwithstanding the foregoing, in no event
may any Performance Goals be established which would permit a Covered
Employee to receive a single Annual Award or a Long-Term Award of more than
200% of such Covered Employee's base annual compensation as of January 1
for the year in which an Award is paid. No payment of any Award may be
made to any Covered Employee unless the material terms of the Performance
Goal under which the compensation is to be paid have been approved by
shareholders of the Company and the Committee has certified in writing that
the Performance Goals and any other material terms of the Award were in
fact satisfied.
(I) MISCELLANEOUS AND ADMINISTRATIVE PROVISIONS
1. All Participants shall be entitled to receive a copy of the Plan
and any amendments made subsequent to its Effective Date.
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<PAGE>
2. The Plan shall be binding upon and inure to the benefit of the
Participants (and their personal representatives), the Company and any
successor organization or organizations which shall succeed to
substantially all of the business and property of the Company, whether
by means of merger, consolidation, acquisition of substantially all of
the assets of the Company or otherwise, including by operation of law.
3. All amounts used for Plan purposes shall be rounded to the
nearest whole dollar.
4. Awards whether in cash or Restricted Stock shall not be subject
to assignment, pledge, lien, or encumbrances of any kind.
5. Participation in the Plan does not guarantee employment by the
Company.
6. Awards shall not be used for any purposes for any employee
benefit plan of the Company.
7. The Plan shall be interpreted under the laws of the State of
Missouri.
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<PAGE>
SPLIT DOLLAR AGREEMENT
AGREEMENT made the 12th day of June, 1985, by and between Michigan Gas
Utilities Company (hereafter called the "Corporation") and James G. Miller
(hereinafter called the "Employee").
WHEREAS, the Employee wants to insure his life, for the benefit and
protection of his family, under a policy to be issued by Massachusetts Mutual
Life Insurance Company (hereinafter called the "Insurer"): and
WHEREAS, the Corporation wants to help the Employee provide the insurance
benefit and protection of his family by contributing from time to time toward
the payment of premiums due on the policy on the Employee's life; and
WHEREAS, The Board of Directors of the Corporation has resolved to enter
into split-dollar life insurance agreements with respect to policies of life
insurance on the lives of selected employees;
NOW THEREFORE, in consideration of the mutual covenants contained herein,
it is agreed between the parties as follows:
1. APPLICATION FOR INSURANCE: The Employee will apply to the Insurer for a
policy on his life in the amount of $500,000.00, and he will do everything
necessary to cause the policy to be issued. When the policy is issued, the
policy number, face amount and type of plan of insurance shall be recorded on
Schedule A attached hereto, and the policy shall then be subject to the terms of
this Agreement.
2. OWNERSHIP OF INSURANCE: The Employee shall be the owner of the policy
on his life acquired pursuant to the terms of this Agreement (hereinafter called
the "Policy"), and he may exercise all the rights of
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<PAGE>
ownership with respect to the Policy except as otherwise hereinafter provided.
3. ELECTION OF DIVIDEND OPTION:
(a) All dividends declared by the Insurer on the Policy shall be
applied to purchase additional paid up insurance on the life of the Employee.
(b) The Employee shall elect the dividend option described in
paragraph (a) of this Section for the Policy. The dividend option which is
elected will not be terminated or changed without the Corporation's written
consent.
4. PAYMENT OF PREMIUMS ON POLICY: The "basic annual premium" which term
shall mean the total annual premium due including premiums due for an Additional
Life Insurance Rider, if any, less (i) premiums for any additional policy
benefits and riders (as specified in Section 7 hereof) and (ii) premiums for
extra mortality ratings, (as defined in paragraph 8(b) hereof), if any, shall be
paid by the Corporation and the Employee in the following manner:
(a) The Corporation shall pay the difference between the basic annual
premium and the cost (calculated by application of Internal Revenue Service
Table PS-58) of the portion of the insurance which the beneficiary or
beneficiaries named by the Employee would be entitled to receive if the
Employee died during the policy year for which such annual premium is paid.
(b) The Employee shall pay the balance of the basic annual premium;
provided, however, that the Company shall provide the Employee with additional
compensation equal to such amount for the first year of the Policy.
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<PAGE>
(c) The Corporation and the Employee shall arrange to have the basic
annual premium and any additional premiums payable in accordance with Sections 7
and 8 hereof paid to the Insurer on the premium due date or within the grace
period allowed by the Policy for the payment of the premium.
5. EMPLOYEE'S OBLIGATION TO CORPORATION: The Employee shall be obligated
to repay to the Corporation the Corporation's cumulative premium contribution
paid under paragraph 4(a) of this Agreement. The obligation of the Employee to
the Corporation shall be payable as provided in Sections 9 and 11 hereof.
6. ASSIGNMENT OR TERMINATION OF POLICY:
(a) The Employee will collaterally assign the Policy to the
Corporation as security for the repayment of the Corporation's cumulative
premium contribution paid under paragraph 4(a) of this Agreement. This
collateral assignment will not be altered or changed without the written
consent of the Corporation.
(b) While this Agreement is in force and effect, the Employee will
neither sell, surrender nor otherwise terminate the Policy without the
Corporation's consent.
7. ADDITIONAL POLICY BENEFITS AND RIDERS: The Employee may add a rider
to the Policy for his own benefit. Upon written request by the Corporation, the
Employee may add a rider to the Policy for the benefit of the Corporation. Any
additional premium for any rider which is added to the policy shall be paid by
the party which will be entitled to receive the proceeds of the rider, except
that the Corporation shall pay the additional premium for a waiver of premium
rider (as defined in the Policy) on behalf of the Employee and the Employee
shall not be obligated to repay said additional
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<PAGE>
premium amounts to the Corporation, and except that any premiums for an
Additional Life Insurance Rider shall be considered part of the basic annual
premium and shall be paid as provided in Sections 4(a) and 4(b) hereof.
8. EXTRA MORTALITY RATING:
(a) In the event the Insurer requires an additional premium over and
above the basic annual Policy premium because of an extra mortality rating, said
additional premium shall be paid by the Corporation on behalf of the Employee
and the Employee shall not be obligated to repay the Corporation said additional
premium amounts paid by the Corporation.
(b) An extra mortality rating shall mean an actuarially determined
amount added to either (i) the basic annual premium or (ii) any additional
premium paid pursuant to Section 7 hereof, due to a determination made by the
Insurer's underwriting department that the Employee is a substandard health
risk.
9. DEATH CLAIMS: If the Employee dies prior to the repayment to the
Corporation of its cumulative premium contribution;
(a) The Corporation shall be entitled to receive a portion of the
death benefits provided under the Policy equal to its cumulative premium
contribution as of the date of death, paid by the Corporation pursuant to
paragraph 4 hereof.
(b) The beneficiary or beneficiaries named by the Employee in the
Policy shall be entitled to receive the amount of the death benefits provided
under the Policy in excess of the amount payable to the Corporation under
paragraph (a) of this Section. This amount shall be paid under the settlement
option elected by the Employee.
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<PAGE>
10. TERMINATION OF AGREEMENT: This Agreement shall terminate on the
occurrence of any of the following events:
(a) written notice given by either party to the other;
(b) termination of the Employee's employment with the Corporation
prior to age 65;
(c) the latter of the Employee becoming eligible for a normal
retirement allowance under the Employees' Retirement Plan or one
year following the due date of the last premium payable under the
Policy;
(d) bankruptcy, receivership or dissolution of the Corporation;
(e) lapse of the Policy for any reason;
(f) upon the written election of the aggrieved party if either the
Corporation or the Employee fails for any reason to make the
contribution required by Section 4 hereof toward payment of any
premium due on the Policy; provided that any election to
terminate this Agreement under this clause must be made in
writing within ninety days after the failure to make the required
contribution occurs;
(g) repayment in full by the Employee of the cumulative premium
contribution made by the Corporation under paragraph 4(a) of this
Agreement provided that upon receipt of such repayment the
Corporation releases the collateral assignment of the Policy made
by the Employee pursuant to Section 6 hereof.
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<PAGE>
11. DISPOSITION OF POLICY ON TERMINATION OF AGREEMENT: If this Agreement
is terminated under paragraph (a), (b), (c), (d), (e) or (f) of Section 10
hereof, the Employee shall have thirty days in which to repay the Corporation
its cumulative premium contribution as of the date of said termination. Upon
receipt of this amount, the Corporation shall release the collateral assignment
of the Policy. If the Employee does not make such repayment within the thirty
day period, the Corporation may enforce any rights which it has under the
collateral assignment of the Policy.
12. INSURANCE COMPANY NOT A PARTY: The Insurer
(a) shall not be deemed to be a party to this Agreement for any
purpose nor in any way responsible for its validity;
(b) shall not be obligated to inquire as to the distribution of any
monies payable or paid by it under the Policy;
(c) shall be fully discharged from any and all liability under the
terms of any policy issued by it, which is subject to the terms of this
Agreement, upon payment or other performance of its obligations in accordance
with the terms of such Policy.
13. AMENDMENT OF AGREEMENT: This Agreement shall not be modified or
amended except by a writing signed by the Corporation and the Employee. This
Agreement shall be binding upon the heirs, administrators or executors and the
successors and assigns of each party of this Agreement.
14. NOTICE: Any notice which either party hereto may be required or
permitted to give to the other shall be in writing and may be delivered
personally or by certified or registered mail, return receipt requested,
addressed as follows:
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<PAGE>
To Michigan Gas Utilities Company, Attention: Secretary of the
Corporation, at 899 South Telegraph Road, P.O. Box 729, Monroe, Michigan 48161
or at such other address as the Corporation, by notice to the Employee, may
designate in writing from time to time; to the Employee, at his address as shown
on the employment records of the Corporation; or at such other address as the
Employee, by notice to the Secretary of the Corporation, may designate in
writing from time to time.
15. STATE LAW: This Agreement shall be subject to and shall be construed
under the laws of the State of Michigan.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
/s/ James G. Miller
-----------------------------
James G. Miller
Employee
Michigan Gas Utilities Company
By: /s/ Paul L. Schreur
-----------------------------
(Corporate Seal)
Attest:
/s/ Marion J. Grajeurh
--------------------------------
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<PAGE>
Schedule A
Policy Number Type of Policy Face Amount
7018606 Limited Payment $500,000.00
Whole Life
<PAGE>
[Mass Mutual Letterhead]
POLICYOWNER ANNUAL STATEMENT FEBRUARY 12, 1995 ANNIVERSARY
DATE PREPARED 2-09-1995
Policy Number: 7018606
Insured's Name: JAMES G MILLER
JAMES G MILLER 008 Plan: Whole Life Paid-up at Age 45
P O BOX 4343 Issue Date: 2/12/85
PUEBLO CO Dividend Option: Paid-up Additional Insurance
81003-0343
INSURANCE SUMMARY
Basic Policy $ 500,000.00
Paid-up Additional Insurance $ 197,688.00
TOTAL INSURANCE COVERAGE $ 697,688.00
CASH VALUE SUMMARY
Basic Policy $ 173,015.00
Paid-up Additional Insurance $ 68,405.87
TOTAL CASH VALUE $ 241,420.87
ADDITIONAL FACTS ABOUT YOUR POLICY
* This statement assumes all premiums have been paid to the statement date.
* Premiums of $ 18,205.00 are payable annually.
* Your 1995 dividend of $ 9,710.19 purchased $ 28,062.00 of paid-up
additional insurance.
* Your policy includes a waiver of premium provision in the event of a
qualifying disability.
Your Mass Mutual Representative Your Mass Mutual Servicing Agency
BOSTON-BERLIN AGENCY
DANIEL S BUSCH, CLU STEPHEN C BERLIN GA
150 WALNUT HILL RD 699 BOYLSTON STREET
CHESTNUT HILL MA 02167 BOSTON MA 02116
TEL: (617) 262-2500
TELE: (617) 325-7474 OR DIRECT ACCESS SERVICE
1-800-272-2216
MASSACHUSETTS MUTUAL LIFE INSURANCE COMPANY SPRINGFIELD MA 01111-0001
<PAGE>
SUPPLEMENTAL RETIREMENT AGREEMENT
THIS SUPPLEMENTAL RETIREMENT AGREEMENT (the "Agreement") is made as of
January 27, 1983, by and between Michigan Gas Utilities Company, a Michigan
corporation ("MGU") and James G. Miller (the "Executive").
WHEREAS, MGU desires to provide for the payment of supplemental
retirement benefits to certain senior executives of MGU in order to attract and
retain executives of superior ability, industry and loyalty;
WHEREAS, the Executive is now serving as a senior executive officer of
MGU and MGU desires to have him remain in such employment;
WHEREAS, the Board of Directors of Michigan Energy Resources Company,
the parent company of MGU, has authorized the entering by MGU into an agreement
with the Executive, providing for substantially the benefits set forth herein;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements herein contained, MGU and the Executive agree as follows:
ARTICLE I
RETIREMENT BENEFITS
1. If the executive shall retire on or after his 65th birthday he
shall be entitled to receive $40,000 per annum ("Supplemental Retirement
Benefit"), payable for the period and in the manner provided in Article II.
<PAGE>
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2. If the Executive shall retire on or after his 55th birthday but
prior to his 65th birthday, he shall be entitled to receive benefits in an
amount per annum equal to the Supplemental Retirement Benefit, reduced by an
amount equal to the product of (a) one-quarter of one percent of the
Supplemental Retirement Benefit and (b) the number of months, or fractions
thereof, by which the date of his retirement shall precede his 65th birthday.
3. Notwithstanding any other provision of this Agreement, if the
employment of the Executive is terminated other than by retirement or death,
neither the Executive nor his Eligible Spouse shall be entitled to any benefits
under this Agreement.
4. For purposes of this Agreement, the Board of Directors of MGU
shall have the sole discretion to determine whether the Executive has retired or
whether his employment with MGU has otherwise terminated.
5. Anything to the contrary contained herein notwithstanding, for
purposes of this Agreement, if the Executive receives benefits under the MGU
Group Long-Term Disability Insurance Plan (or any successor plan which provides
for similar benefits), the Executive shall be deemed to be in the employ of MGU
for so long as he shall receive such benefits thereunder.
As used in this Agreement, "MGU" shall mean Michigan Gas Utilities
Company, or any successor by merger, purchase of all or substantially all of the
assets and business of MGU, or otherwise.
As used in this Agreement, "Eligible Spouse" shall mean the spouse of
the Executive who was legally married to the Executive at the date of the
Executive's death.
<PAGE>
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Article II
PAYMENT OF RETIREMENT BENEFITS
1. Retirement benefits paid under this Agreement as a result of the
Executive retiring or having deemed to have retired pursuant to Section 2 of
Article III, after the first day of the month following his 65th birthday shall
be paid monthly in approximately equal installments for the lesser of (a) 15
YEARS or (b) the life of the Executive and, following his death, the life of his
Eligible Spouse.
2. Retirement benefits paid under this Agreement as a result of any
other event shall be paid monthly in approximately equal installments until the
occurrence of the earlier of (a) payment of the benefit one month prior to the
Executive reaching his Eightieth Birthday or (b) the death of the Executive and,
following his death, the death of his Eligible Spouse. For purposes of this
Agreement, Eightieth Birthday means the day on which the Executive reaches the
age of 80, if that date is the first day of a month, and otherwise, the first
day of the month following the month in which the Executive reaches the age
of 80.
3. The initial payment of retirement benefits under Section 1 or
Section 2 of Article I, as the case may be, shall be made on the date of the
Executive's retirement from MGU, if that date is the first day of a month, and
otherwise on the first day of the month next following the date of retirement.
4. Except as otherwise provided in Section 8 of Article V, only the
Executive, or, as provided in Article III, his Eligible Spouse, may receive
retirement benefits hereunder, and no other person, whether
<PAGE>
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claiming under or through the Executive or his Eligible Spouse, or otherwise,
shall have any rights whatsoever under this Agreement.
Article III
SPOUSE'S BENEFITS
1. In the event of the death of the Executive after his retirement,
but prior to payment to him of all the retirement benefits he is entitled to
receive pursuant to either Section 1 or Section 2 of Article II, as the case may
be, his Eligible Spouse shall be entitled to the retirement benefits theretofore
received by the Executive under Article I or to the retirement benefits
resulting from the operation of Section 2 of this Article III, payable for the
period and in the manner provided in this Article III.
2. In the event of the death of the Executive on or after his 55th
birthday, but prior to his retirement, he shall be deemed to have retired
immediately prior to his death, and his Eligible Spouse shall be entitled to
receive the retirement benefits that the Executive would have received under
Section 2 of Article I.
3. The Eligible Spouse's retirement benefits under Section 2 of this
Article III shall be paid monthly in approximately equal installments for the
lesser of (a) the period benefits would have been payable to the Executive under
this Agreement had his death not occurred, or (b) the life of the Eligible
Spouse.
4. In the event of the death Executive prior to his 55th birthday,
his Eligible Spouse shall be entitled to receive benefits in an amount per
annum equal to the Supplemental Retirement Benefit.
<PAGE>
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reduced by an amount equal to the product of (a) one-quarter of one percent of
the Supplemental Retirement Benefit and (b) the number of months, or fractions
thereof, by which the date of his death shall precede his 65th birthday should
he have lived to that date.
5. The Eligible Spouse's benefits under Section 4 of this Article III
shall be paid monthly in approximately equal installments until the occurrence
of the earlier of (a) payment of the benefit one month prior to the Executive's
Eightieth Birthday should he have lived to that date, or (b) the life of the
Eligible Spouse.
6. The initial payment to the Eligible Spouse of benefits under this
Article III shall be made on the date of the Executive's death, if that date is
the first day of a month, and otherwise on the first day of the month
following the date of the Executive's death.
Article IV
AMENDMENT AND TERMINATION
The Board of Directors of MGU shall have the right, without the
consent of the Executive or his Eligible Spouse, to amend or modify this
Agreement from time to time or to terminate this Agreement entirely at any time;
PROVIDED, HOWEVER, that if, at the time of such action, payment of retirement
benefits under this Agreement have theretofore been made, such action shall not
in any manner adversely affect the right of the Executive or of his Eligible
Spouse, as the case may be, to the continued receipt of such payments in
accordance with this Agreement.
<PAGE>
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Article V
MISCELLANEOUS
1. Neither the Executive nor his Eligible Spouse shall have any right
or interest, whether vested or otherwise, in this Agreement or its continuance,
or in or to the payment of any retirement benefits under this Agreement, unless
and until all the terms, conditions and provisions of this Agreement that effect
such retirement benefits and the payment thereof shall have been fully compiled
with, as specifically provided in this Agreement; PROVIDED, HOWEVER, that
nothing in this section shall be construed to limit in any way the right of MGU
under Article IV to amend or terminate this Agreement.
2. Any retirement benefits under this Agreement shall be payable only
from the general assets of MGU.
3. This Agreement shall not in any way affect the right and power of
MGU to dismiss any employee or otherwise terminate the employment or change the
terms of employment or amount of compensation of any employee or any time for
any reason, with or without cause.
4. MGU shall not merge or consolidate with any other corporation or
business unless and until such other corporation or business shall expressly
assume the responsibilities of MGU herein set forth. MGU further agrees that if,
at any time prior to the making of the last payment to be paid hereunder to the
Executive or his Eligible Spouse, as the case may be, it shall liquidate or
dissolve, it shall, before any such liquidation or dissolution, make proper
provisions for the continuation of the payments in accordance with this
Agreement.
<PAGE>
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5. The entering into this Agreement by the Executive shall
conclusively bind the Executive and his Eligible Spouse to any action or
decision taken or made to be taken or to be made pursuant to or respecting this
Agreement by MGU or the Board of Directors of MGU.
6. this Agreement shall not be deemed a substitute for any
retirement, death, disability or other employee benefit plan or arrangement that
may now or hereafter be provided for employees of MGU generally. Any such plan
or arrangement may be authorized by the Board of Directors of MGU and payments
thereunder may be made independently of this Agreement.
7. The assignment, pledge or encumbrance of any kind of the benefits
under this Agreement shall not be permitted or recognized.
8. Should any person then receiving retirement benefits under this
Agreement be declared or adjudicated incompetent by any court having
jurisdiction over such person, retirement benefits under this Agreement may be
paid to the legal representative of such person for so long as the incompetency
continues, but in no case for a period longer than the remainder of the period
of payment established in accordance with Article I or Article III, whichever is
applicable. Such payment of retirement benefits to such legal representative
shall absolve MGU absolutely from any further liability whatsoever therefor.
<PAGE>
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9. The provisions of this Agreement shall be construed, administered
and enforced according to the laws of the State of Michigan.
MICHIGAN GAS UTILITIES COMPANY
Dated: April 14, 1983 /s/ Paul L. Schreur
-------------- --------------------------
By Paul L. Schreur
Vice Chairman
Dated: April 14, 1983 /s/ James G. Miller
-------------- ---------------------------
James G. Miller
President
<PAGE>
[EXECUTION COPY]
LETTER AMENDMENT
Dated as of
December 8, 1994
To the Lenders listed on the
signature pages below
Ladies and Gentlemen:
We refer to the Credit Agreement, dated as of December 13, 1993 (the
"CREDIT AGREEMENT"), among the undersigned, you and Citibank, N.A., as Agent.
Unless otherwise defined herein, the terms defined in the Credit Agreement are
used herein as therein defined.
The Borrower hereby requests that the Lenders consent to certain
adjustments in the Applicable Margins and the commitment fees, to which changes
you have indicated your willingness to agree. Accordingly, the Borrower and all
the Lenders agree, subject to the satisfaction of the conditions set forth
below, as follows:
(a) The definition of the term "APPLICABLE MARGIN" set forth in Section
1.01 of the Credit Agreement is amended and restated in its entirety
as follows:
""APPLICABLE MARGIN" means, for any Base Rate Advances, 0.00% PER
ANNUM, and for any CD Rate Advance or Eurodollar Rate Advance, the
percentage PER ANNUM set forth below, determined in accordance with
the following table by reference to the Applicable Rating Level in
effect from time to time:
<PAGE>
2
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
APPLICABLE RATING LEVEL EURODOLLAR RATE ADVANCE CD RATE ADVANCE
APPLICABLE MARGINS APPLICABLE MARGINS
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
I 0.35% 0.475%
--------------------------------------------------------------------------------
II 0.475% 0.60%
--------------------------------------------------------------------------------
III 0.55% 0.675%
--------------------------------------------------------------------------------
IV 0.90% 1.025%
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Any change in the Applicable Rating Level shall cause an immediately
effective change in the Applicable Margins for Eurodollar Rate
Advances and CD Rate Advances."
(b) The Credit Agreement is amended by adding the following definition in
alphabetical order to Section 1.01:
"APPLICABLE RATING LEVEL" shall be determined at any time on the
basis of the lower of the S&P Rating or Moody's Rating in accordance
with the following table, which Applicable Rating Level shall be
redetermined effective on the date of the announcement of a change in
the S&P Rating or the Moody's Rating:
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
APPLICABLE
RATING LEVEL S&P RATING MOODY'S RATING
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
I A- or higher A3 or higher
--------------------------------------------------------------------------------
II Lower than A- but Lower than A3 but
higher than BBB- higher than Baa3
--------------------------------------------------------------------------------
III BBB- Baa3
--------------------------------------------------------------------------------
IV Lower than BBB- or Lower than Baa3 or
unrated unrated
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
The Borrower agrees to notify the Agent promptly upon each change in
the Moody's Rating or the S&P Rating."
<PAGE>
3
(c) Section 2.04(a) of the Credit Agreement is amended and restated in its
entirety as follows:
"(a) The Borrower agrees to pay to the Agent for the account of
each Lender a commitment fee on the average daily unused portion of
such Lender's Commitment (after giving effect to any Auction
Reduction) from the date hereof in the case of each Bank and from the
effective date specified in the Assignment and Acceptance pursuant to
which it became a Lender in the case of each other Lender until the
earlier to occur of the Termination Date and, in the case of the
termination in whole of a Lender's Commitment pursuant to Section
2.05, the date of such termination, payable on the last day of each
March, June, September and December during such period (commencing
December 31, 1993) and on the earlier to occur of the Termination Date
and, in the case of the termination in whole of a Lender's Commitment
pursuant to Section 2.05, the date of such termination, at the rate
determined in accordance with the following table by reference to the
Applicable Rating Level in effect from time to time:
----------------------------------------------------------
----------------------------------------------------------
APPLICABLE COMMITMENT
RATING LEVEL FEE RATE
----------------------------------------------------------
----------------------------------------------------------
I 0.15%
----------------------------------------------------------
II 0.1875%
----------------------------------------------------------
III 0.20%
----------------------------------------------------------
IV 0.35%
----------------------------------------------------------
----------------------------------------------------------
Any change in the Applicable Rating Level shall cause an immediately
effective change in the commitment fee rate."
On and after the effective date of this letter amendment, each reference in
the Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like
import referring to the Credit Agreement, and each reference in the Notes to
"the Credit Agreement", "thereunder", "thereof" or words of like import
referring to the Credit Agreement, shall mean and be
<PAGE>
4
a reference to the Credit Agreement, as amended by this letter amendment. The
Credit Agreement, as amended by this letter amendment, is and shall continue to
be in full force and effect and is hereby in all respects ratified and
confirmed.
If you agree to the terms and provisions hereof, please evidence such
agreement by executing and returning thirty counterparts of your signature page
to this letter amendment to the Agent, in care of King & Spalding, 120 West 45th
Street, 32nd Floor, New York, New York 10036, Attention of Jeff V. Nelson, who
will cause fully executed counterparts to be distributed to each of us upon his
receipt thereof. This letter amendment shall become effective as of the date
first written above if, on or before such date, counterparts of this letter
amendment shall have been executed by all the Lenders. This letter amendment
shall be effective solely for the purpose described herein and shall have no
effect on any other provision contained in the Credit Agreement. This letter
amendment shall be governed by, and construed in accordance with, the laws of
the State of New York.
<PAGE>
5
This letter amendment may be executed in any number of counterparts and by
any combination of parties hereto in separate counterparts, each of which
counterparts shall be an original and all of which taken together shall
constitute one and the same agreement.
Very truly yours,
UTILICORP UNITED INC.
By
---------------------------------------
Name:
Title:
Agreed as of the date
first above written:
CITIBANK, N.A., as Agent and a Lender
By
---------------------------------------
Name:
Title:
<PAGE>
[EXECUTION COPY]
LETTER AMENDMENT
Dated as of
December 8, 1994
To the Lenders listed on the
signature pages below
Ladies and Gentlemen:
We refer to the Credit Agreement, dated as of December 13, 1993 (the
"CREDIT AGREEMENT"), among the undersigned, you and Citibank, N.A., as Agent.
Unless otherwise defined herein, the terms defined in the Credit Agreement are
used herein as therein defined.
Pursuant to Section 2.17 of the Credit Agreement, the Borrower hereby
requests that the Lenders consent to a 360-day extension of the Termination
Date, to December 3, 1995. In addition, the Borrower hereby requests that the
Lenders consent to a waiver of the time requirements of Section 2.17 of the
Credit Agreement for submitting this request and obtaining the consent of the
Lenders; provided that the consent of all Lenders shall be obtained no later
than December 8, 1994.
You have indicated your willingness to agree to the foregoing. You have
also indicated your willingness to adjust the Applicable Margins and the
commitment fees. Accordingly, the Borrower and all the Lenders agree, subject
to the satisfaction of the conditions set forth herein, as follows:
a. The Lenders consent to the Borrower's request for an extension of the
Termination Date to December 3, 1995.
b. The definition of the term "APPLICABLE MARGIN" set forth in Section
1.01 of the Credit Agreement is amended and restated in its entirety
as follows:
"APPLICABLE MARGIN" means, for any Base Rate Advances, 0.00% PER
ANNUM, and for any CD Rate Advance or Eurodollar Rate Advance, the
percentage PER ANNUM set forth below, determined in accordance with
the following
<PAGE>
2
table by reference to the Applicable Rating Level in effect from time
to time:
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
APPLICABLE RATING EURODOLLAR RATE ADVANCE CD RATE ADVANCE
LEVEL APPLICABLE MARGINS APPLICABLE MARGINS
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
I 0.3125% 0.4375%
--------------------------------------------------------------------------------
II 0.4325% 0.5575%
--------------------------------------------------------------------------------
III 0.50% 0.625%
--------------------------------------------------------------------------------
IV 0.85% 0.975%
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Any change in the Applicable Rating Level shall cause an immediately
effective change in the Applicable Margins of Eurodollar Rate Advances
and CD Rate Advances."
c. The Credit Agreement is amended by adding the following definition in
alphabetical order to Section 1.01:
"APPLICABLE RATING LEVEL" shall be determined at any time on the
basis of the lower of the S&P Rating or Moody's Rating in accordance
with the following table, which Applicable Rating Level shall be
redetermined effective on the date of the announcement of a change in
the S&P Rating or the Moody's Rating:
<PAGE>
3
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
APPLICABLE
RATING LEVEL S&P RATING MOODY'S RATING
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
I A- or higher A3 or higher
--------------------------------------------------------------------------------
II Lower than A- but Lower than A3 but
higher than BBB- higher than Baa3
--------------------------------------------------------------------------------
III BBB- Baa3
--------------------------------------------------------------------------------
IV Lower than BBB- Lower than Baa3 or
unrated unrated
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
The Borrower agrees to notify the Agent promptly upon each change in
the Moody's Rating or the S&P Rating."
d. Section 2.04(a) of the Credit Agreement is amended and restated in its
entirety as follows:
"(a) The Borrower agrees to pay to the Agent for the account of
each Lender a commitment fee on the average daily unused portion of
such Lender's Commitment (after giving effect to any Auction
Reduction) from the date hereof in the case of each Bank and from the
effective date specified in the Assignment and Acceptance pursuant to
which it became a Lender in the case of each other Lender until the
earlier to occur of the Termination Date and, in the case of the
termination in whole of a Lender's Commitment pursuant to Section
2.05, the date of such termination, payable on the last day of each
March, June, September and December during such period (commencing
December 31, 1993) and on the earlier to occur of the Termination Date
and, in the case of the termination in whole of a Lender's Commitment
pursuant to Section 2.05, the date of such termination, at the rate
determined in accordance with the following table by reference to the
Applicable Rating Level in effect from time to time:
<PAGE>
4
-----------------------------------------------
-----------------------------------------------
APPLICABLE COMMITMENT
RATING LEVEL FEE RATE
-----------------------------------------------
-----------------------------------------------
I 0.125%
-----------------------------------------------
II 0.15%
-----------------------------------------------
III 0.175%
-----------------------------------------------
IV 0.30%
-----------------------------------------------
Any change in the Applicable Rating Level shall cause an immediately
effective change in the commitment fee rate."
On and after the effective date of this letter amendment, each reference in
the Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like
import referring to the Credit Agreement, and each reference in the Notes to
"the Credit Agreement", "thereunder", "thereof" or words of like import
referring to the Credit Agreement, shall mean and be a reference to the Credit
Agreement, as amended by this letter amendment. The Credit Agreement, as
amended by this letter amendment, is and shall continue to be in full force and
effect and is hereby in all respects ratified and confirmed.
If you agree to the terms and provisions hereof, please evidence such
agreement by executing and returning thirty counterparts of your signature page
to this letter amendment to the Agent, in care of King & Spalding, 120 West 45th
Street, 32nd Floor, New York, New York 10036, Attention of Jeff V. Nelson, who
will cause fully executed counterparts to be distributed to each of us upon his
receipt thereof. This letter amendment shall become effective as of the date
first written above if, on or before such date, (i) counterparts of this letter
amendment shall have been executed by all the Lenders and (ii) the Agent shall
have received the documents required to be delivered to the Agent and the
Lenders by the Borrower pursuant to Section 2.17 of the Credit Agreement,
including the opinions required thereby in substantially the forms of Exhibit A
and Exhibit B hereto. This letter amendment shall be effective solely for the
purpose described herein and shall have no effect on any other provision
contained in the Credit Agreement. This letter amendment shall be governed by,
and construed in accordance with, the laws of the State of New York.
<PAGE>
5
This letter amendment may be executed in any number of counterparts and by
any combination of parties hereto in separate counterparts, each of which
counterparts shall be an original and all of which taken together shall
constitute one and the same agreement.
Very truly yours,
UTILICORP UNITED INC.
By____________________________
Name:
Title:
Agreed as of the date
first above written:
CITIBANK, N.A., as Agent and a Lender
By___________________________
Name:
Title:
<PAGE>
Exhibit 11
UtiliCorp United Inc.
Statement regarding Computation of Per Share Earnings
<TABLE>
<CAPTION>
For the Year Ended
December 31,
1994 1993 1992
----------------------------------
Line No.
----------
<S> <C> <C> <C>
Earnings Available for Common Shares:
(a) Earnings available for common shares as reported 91.4 79.5 46.0
(b) Elimination of interest on convertible subordinated
debenture, net of tax .55 .64 .83
(c) Elimination of dividends on cumulative
convertible preference stock .93 4.88 --
----------------------------------
(d) Fully Diluted Earnings Available 92.9 85.0 46.8
==================================
Weighted Average Common Shares Outstanding:
(e) Primary weighted average shares outstanding
as reported 43.97 40.74 34.93
(f) Assumed conversion of convertible subordinated
debenture .55 .66 .82
(g) Assumed conversion of cumulative convertible
preference shares .66 2.87 --
----------------------------------
(h) Fully Diluted Weighted Average Shares
Outstanding 45.18 44.27 35.75
==================================
Earnings Per Common Share:
Primary (a/e) $2.08 $1.95 $1.32
Fully Diluted (d/h) 2.06 1.92 1.31
</TABLE>
<PAGE>
FINANCIAL HIGHLIGHTS
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
IN MILLIONS EXCEPT PER SHARE 1994 1993 % Change
---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $1,514.6 $1,571.6 (3.6)%
Income from operations before charge (a) 230.5 222.0 3.8
Income from operations 230.5 152.2 51.4
Net income 94.4 86.4 9.3
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
Primary earnings per common share $2.08 $1.95 6.7%
Cash dividends per common share 1.70 1.62 4.9
Book value per common share 20.24 20.27 (.1)
Primary average common shares outstanding 43.97 40.74 7.9
---------------------------------------------------------------------------------------------------------
Total assets $3,111.1 $2,850.5 9.1%
Total capitalization and short-term debt (b) 2,230.3 2,017.1 10.6
Common equity/capitalization and short-term debt 40.7% 42.2% (3.6)
Return on average common equity 10.24% 9.84% 4.1
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
<FN>
(a) RESTRUCTURING CHARGE OF $69.8 MILLION IN 1993.
(b) INCLUDES CURRENT MATURITIES OF LONG-TERM DEBT. SHORT-TERM DEBT DOES NOT
REPRESENT PERMANENT CAPITAL, AND WILL BE FINANCED WITH DEBT AND EQUITY
SECURITIES CONSIDERING FINANCIAL MARKET CONDITIONS.
</TABLE>
<TABLE>
<CAPTION>
REVENUES
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 1,514.6
1993 1,571.6
1992 1,298.9
---------------------------------------------------------------------------
<CAPTION>
INCOME FROM OPERATIONS BEFORE CHARGES*
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 230.5
1993 222.0
1992 186.7
---------------------------------------------------------------------------
<FN>
* RESTRUCTURING CHARGE OF $69.8 MILLION IN 1993; UNUSUAL LOSS PROVISION OF
$17.7 MILLION IN 1992.
</FN>
<CAPTION>
NET INCOME
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 94.4
1993 86.4
1992 52.9
---------------------------------------------------------------------------
<CAPTION>
EARNINGS PER SHARE VS. DIVIDENDS PAID
---------------------------------------------------------------------------
DOLLARS
---------------------------------------------------------------------------
<S> <C>
1994 2.08
1.70
1993 1.95
1.62
1992 1.32
1.60
---------------------------------------------------------------------------
<FN>
EARNINGS PER SHARE DIVIDENDS PAID
</FN>
<CAPTION>
TOTAL CAPITALIZATION AND SHORT-TERM DEBT
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 2,230.3
1993 2,017.1
1992 1,883.8
---------------------------------------------------------------------------
<CAPTION>
RETURN ON AVERAGE COMMON EQUITY
---------------------------------------------------------------------------
PERCENT
---------------------------------------------------------------------------
<S> <C>
1994 10.24
1993 9.84
1992 6.93
---------------------------------------------------------------------------
<CAPTION>
AVERAGE DAILY TRADING VOLUME
---------------------------------------------------------------------------
THOUSAND SHARES
---------------------------------------------------------------------------
<S> <C>
1994 56.9
1993 72.3
1992 73.3
---------------------------------------------------------------------------
<CAPTION>
MARKET VS. BOOK VALUE PER SHARE
---------------------------------------------------------------------------
DOLLARS
---------------------------------------------------------------------------
<S> <C>
1994 26.50
20.24
1993 31.75
20.27
1992 27.63
18.66
---------------------------------------------------------------------------
<FN>
MARKET BOOK VALUE PER SHARE
</TABLE>
UTILICORP
1
<PAGE>
[Graphic]
<PAGE>
FELLOW SHAREHOLDERS:
In 1994 UtiliCorp had record net income and earnings per share grew by 6.7
percent. Our company raised the common dividend by 2.4 percent, initiated both
utility and non-regulated acquisitions and added to its operations overseas. In
December we launched a national marketing strategy that will have long-term
significance for UtiliCorp's second decade of growth.
BECOMING A NATIONAL UTILITY. In the first 10 years since UtiliCorp was formed
from Missouri Public Service Company, we went from being a mostly electric
utility in western Missouri to become a diversified, international energy
provider. Today we have facilities in 17 states and provide energy services to
electric and gas customers in 45 states, two provinces of Canada, the United
Kingdom and New Zealand.
Our unique combination of geographic diversity and a broad range of energy
products and services has positioned UtiliCorp to become the first truly
national utility company in the United States. There are compelling, competitive
reasons for pursuing this national strategy.
INTRODUCING OUR NATIONAL BRAND. To carry out our ambitious plans to market
energy nationwide, UtiliCorp has introduced EnergyOne-SM-, a new marketing
concept that includes the industry's first national brand name. We will unite
UtiliCorp's products, services and energy delivery capabilities under the
EnergyOne banner as markets are available around the country.
Consumers of energy are demanding choice and lower cost. UtiliCorp's
EnergyOne service portfolios will provide both. We are already marketing energy
through other utilities in states where we don't own any wires or pipes, and we
have been successful at lowering our own
[Photo]
RICHARD C. GREEN, JR.
Chairman and President
UTILICORP
3
<PAGE>
costs of producing power and purchasing gas where we serve as the local utility.
We are differentiating our EnergyOne products and services from those of
our competition by tailoring them for specific market segments, providing
flexible pricing and fielding a national sales and marketing effort. We are also
introducing our business customers to new technology-based solutions that can
make their operations more efficient and their energy easier to buy and manage.
EMPLOYEE PARTICIPATION. Operating a business during a time of major transition
and accelerating change places many extra demands on employees at all levels.
They must not only learn new skills but also adopt new attitudes and behaviors
to successfully turn their enterprise into a more competitive, market-driven
company.
The men and women of UtiliCorp have not merely accepted these challenges.
They have applied great energy, enthusiasm and teamwork in generating the ideas
behind our new strategy and structure. It is their drive and knowledge that will
bring about the successes of our second decade.
COMPETING ON COST. The rates charged by UtiliCorp's utilities have positioned us
to successfully defend our core markets. They also compare favorably with rates
charged by utilities in other parts of the country where we intend to compete
for market share as deregulation progresses.
Our residential electric prices today are among the lowest in the country
at 6.6 cents per kilowatt-hour, compared to the U.S. average of more than 8.3
cents. For natural gas, our average price of $5.11 per thousand cubic feet is
lower than the $5.87 national average.
Our costs for the production of electricity also position us favorably, and
keep improving. Compared to other Midwest utilities, our 3.14 to 3.44 cents per
kilowatt-hour is at the lower end of the scale, while some competitors' costs
are as high as 5.75 cents. Over the last four years, we reduced generating costs
at our major Missouri facility by 28 percent.
In non-regulated gas marketing, we also have been an effective competitor.
By providing major cost savings to industrial and very large commercial
customers, we have won initial contracts and then turned them into larger
national accounts. UtiliCorp's consolidated gas purchasing operation set up in
1993 to serve our distribution utilities has proven to be a competitive
advantage in support of our gas marketing efforts.
UTILICORP
4
<PAGE>
FIRST STEPS IN ELECTRIC DEREGULATION. UtiliCorp received conditional approval
from the Federal Energy Regulatory Commission in January 1995 to begin marketing
electricity in various parts of the country the way it has marketed natural gas
nationally since 1986. The new Aquila Power subsidiary is operating this
business, among the first of its kind in this country. Electricity futures
contracts are expected to join gas futures trading by the New York Mercantile
Exchange by 1996, furthering development of this new national energy market.
We expect that electric power marketing and gas marketing both will
eventually reach the residential market, at which point retail consumers will
have extensive choices of energy supplier, as they do with long-distance phone
service. UtiliCorp views retail competition in electricity as an opportunity,
not a threat. Our costs for power generation are extremely competitive with
other sources and the national market for power is very large, providing
significant opportunities for growth.
We also received approval in January to provide open access to UtiliCorp's
electric transmission system to large volume customers purchasing power for
resale. Since customers will now pay a fee or access charge to use the system as
a common carrier, this is a significant step toward an open and competitive
market.
GROWTH THROUGH ACQUISITIONS. Asset-based growth fueled by acquisitions, mergers
and partnerships remains a vital part of UtiliCorp's strategy. The market-based
growth provided by the national EnergyOne brand strategy is not asset-driven. It
brings an additional avenue for expansion that extends the potential value of
our energy assets at relatively little cost.
During 1994 and early 1995, UtiliCorp completed four purchases that fit
very well with existing operations and the national utility strategy. At the end
of September, we acquired Kansas gas distribution and transmission systems of
NorAm Energy Corp. for $23 million. The systems serve about 22,000 customers in
Wichita and surrounding communities.
In January 1995, we bought a 218-mile intrastate natural gas pipeline
system in Missouri from Edisto Resources Corporation for $75 million. The
purchase includes a pipeline that crosses the Mississippi River north of St.
Louis and the gas distribution system at Fort Leonard Wood, Missouri, home of a
major military base. All of these properties provide strategic opportunities to
extend UtiliCorp's business presence into eastern Missouri.
UTILICORP
5
<PAGE>
Our commercial customer base for non-regulated gas marketing was
significantly strengthened in January 1995 with the purchase of Broad Street Oil
& Gas Company. Broad Street is an Ohio-based gas marketing firm that marketed 30
billion cubic feet of gas in 1994. With more than 10,000 commercial customers in
nine states, including California and Illinois, it's an ideal fit with our
existing commercial gas marketing operations and provides a foundation for
aggressive, nationwide growth into mass markets.
Aquila Gas Pipeline Corporation, an 82-percent-owned subsidiary, acquired
Tristar Gas Company in January 1995 for $16.3 million. Tristar owns interests in
various gas gathering, processing and marketing properties in Texas, similar to
Aquila's.
INTERNATIONAL EXPANSION. UtiliCorp continued laying the foundation for long-term
growth in its businesses overseas during 1994. In the United Kingdom, earnings
from United Gas and our joint ventures to market natural gas in the U. K. were
up considerably from their first profits in 1993. If Parliament approves,
pending measures will open the British residential market to competition,
providing access to another 18 million customers.
UtiliCorp plans to expand its presence in New Zealand in 1995 by becoming a
20 percent shareholder in Power New Zealand Ltd., one of the country's largest
electric utilities, for approximately $55 million. We have also agreed to
acquire Power New Zealand's 18 percent interest in Energy Direct Corporation
Ltd., another electric utility, for about $21 million.
UtilCo Group, our independent power production subsidiary, agreed in
October to become an equity partner in its first international project, a
60-megawatt generating plant to be built in Kingston, Jamaica. UtilCo Group
will contribute about $11 million and hold a 21 percent interest. When the
plant begins commercial operations in 1996, it is expected to supply more than
10 percent of Jamaica's electricity needs.
BOARD OF DIRECTORS. Irvine O. Hockaday, Jr. was named to the board of directors
in February 1995. He is president and chief executive officer of Hallmark Cards.
His perspective as leader of a competitive, international marketing company will
be of great value to UtiliCorp as we embark on our new strategy.
Don R. Armacost plans to retire from the board in May 1995. I have
appreciated his steady support over the 12 years he has served as a director.
He helped steer the creation of UtiliCorp and its first decade of growth.
UTILICORP
6
<PAGE>
EMPLOYEE OWNERSHIP. Over the years our employees have participated in several
programs which enable them to share a stake in our future success by acquiring
UtiliCorp common stock. Currently more than 95 percent of employees are
shareholders, and together we hold about 14 percent of the total shares
outstanding. UtiliCorp is a leader in the utility industry in terms of employee
ownership. On page 17 of this report we recognize UtiliCorp Partners, employees
who have accumulated shares worth at least twice their annual base pay.
LOOKING AHEAD. Our target for earnings growth in 1995 is again 4 to 6 percent.
UtiliCorp is strongly positioned to take advantage of the opportunities that lie
ahead. We have the financial, marketing and management expertise to succeed in
a highly competitive environment. We already have extensive experience competing
successfully in deregulated energy markets. On the gas side of our business,
we've done it for nearly a decade. Now we will apply everything we've learned as
we make changes in the way we market electricity.
We will continue leading the process of redefining our industry. Combining
innovation and aggressive entry into new markets, we plan to be the one the
competition must react to. We want to set the competitive standard by which
others are measured.
Our two growth strategies, one asset-based and one market-based, complement
each other. Success in either one will ensure that our company prospers. We
expect to succeed in both.
For UtiliCorp, 1995 will be a very challenging and exciting year as we turn
plans into actions. I am looking forward to keeping you informed as the year
progresses.
/s/ RICHARD C. GREEN JR.
Richard C. Green, Jr., Chairman and President, February 15, 1995
UTILICORP
7
<PAGE>
[Graphic]
ROLLING OUT OUR BRAND NAME
UtiliCorp is running its products, services and energy delivery capabilities
under the banner of EnergyOne, the utility industry's first national brand name.
The EnergyOne portfolio of services will provide customers with a broad range of
energy solutions nationwide, and competitive pricing.
<PAGE>
QUESTIONS & ANSWERS
UTILITY DEREGULATION
Q. WHAT ARE SOME OF THE MAJOR WAYS THAT DEREGULATION IS ALTERING THE U.S.
UTILITY INDUSTRY?
A. At an accelerating pace, deregulation has begun changing the electric
business much as it transformed the natural gas business in prior years. Gas and
electricity today are considered to be commodities, and the pipes and wires used
to transport them are becoming common carriers accessible to others. Territorial
monopolies and capital-intensive ownership of assets are declining in
importance. Companies from other industries already have begun to enter the gas
and electric business as the regulatory hurdles fade.
Utility companies that do not change are the most likely to feel the
pressure as competition heats up in the next few years. The ability to capture
new markets through innovative marketing, advanced technology and superior
service is becoming paramount. The needs of energy customers are the driving
force behind the changes in the industry and in UtiliCorp's strategy.
Q. HOW HAS DEREGULATION AFFECTED YOUR CORPORATE STRATEGY?
A. To go from operating a protected, territorial monopoly to running an
aggressive, broad-based marketing company involves many changes in skills and
behavior. It also requires different standards for measuring success. Like
consumer product companies, we now must think in terms of market share on a
national scale.
Ten years ago, UtiliCorp handled about .1 percent of the total U.S. energy
market as measured in Btu's, or British thermal units. As a result of our growth
strategy, by 1994 the company's national market share had grown to about .5
percent. UtiliCorp's goal now is to triple its present share of the U.S. energy
market as quickly as possible. A market share of 1.5 percent would about equal
that currently held by the nation's largest utilities.
We will continue to pursue opportunities to grow through mergers,
acquisitions and partnerships as we work to extend the reach of EnergyOne-SM-.
The EnergyOne strategy builds on UtiliCorp's regional recognition and reputation
for excellent service and takes them to a national level. It also helps us offer
more energy products and services to customers currently using only part of what
we can provide. All of these efforts are designed to add market share.
Q. HOW WILL THE "INFORMATION SUPERHIGHWAY" AFFECT THE WAY YOU DO BUSINESS IN THE
FUTURE?
A. When deregulation of gas and electricity reaches residential and small
commercial customers, consumers will have an array of choices in suppliers and
service options. One way to act on those choices will be to access the
information superhighway through a personal computer or interactive television.
UtiliCorp is already planning how it will use online information systems
and shopping channels to market EnergyOne products and services nationally. We
envision the day customers can sign up for energy delivery, select billing
options or order home energy audits from their living rooms.
NEW STRATEGIC DIRECTION
Q. HOW DO YOU KNOW THAT YOUR NEW STRATEGY WILL BE WELL
RECEIVED IN THE MARKETPLACE?
A. Designing UtiliCorp's new marketing plan began with a fresh look at current
customers, as well as potential customers and how best to reach them. We found a
very strong base on which to build.
UtiliCorp already serves more than one fourth of the Fortune 500 companies.
These customers have grown used to the cost savings that came with gas
deregulation and are eager for the same benefits in their electric service. They
also welcome our help in designing energy systems that improve their industrial
processes, provide competitive advantage and increase profit margins. UtiliCorp
benefits by attracting and retaining these major customers and increasing our
energy sales and portfolio of services when their businesses expand.
UTILICORP
9
<PAGE>
Deregulation has enabled us to market natural gas to commercial customers
outside our regulated utility territories. Through our gas purchasing power and
transportation network, we are now providing cost savings of up to 35 percent to
commercial users in 14 states. This is another significant market opportunity we
intend to pursue nationwide.
Q. WILL THE CHANGES IN YOUR ENERGY BUSINESSES BENEFIT THE RESIDENTIAL CONSUMERS
SERVED BY UTILICORP?
A. For now, our new EnergyOne marketing programs are primarily serving the
wholesale, industrial and commercial markets. Eventually, residential customers
will also be allowed to choose their energy providers, much as choice has
evolved in long-distance telephone services. To serve this vast market, we are
tailoring how energy use is structured, measured and billed. We are offering
programs to reduce energy costs and take advantage of new mass market energy
technologies, and pricing our products and services to fit customers' needs. We
are also guaranteeing that our customers will be pleased with their EnergyOne
services.
Q. DOES THE NEW STRATEGY REQUIRE MAJOR CHANGES IN THE COMPANY'S MANAGEMENT
STRUCTURE?
A. Over the past two years, UtiliCorp has modified its management structure and
strengthened its leadership team to ensure that we are a vigorously competitive
company. We have added people with expertise in technology and extensive
experience in deregulated industries such as airlines and telecommunications. We
have also shifted from a portfolio management style to become a more aggressive
and efficient operating company unified by a national brand and a comprehensive
marketing strategy.
In order to facilitate this change in perspective, during 1994 we realigned
our eight utilities and other operations into four business groups focused on
providing single-source energy solutions to the customer. This new alignment
places all our U.S. electric and gas distribution operations into a single
business group; integrates the management of all electric generation and
transmission assets, including independent power projects; adds the new electric
power marketing business to Aquila's non-regulated natural gas operations;
unifies large account sales and provides a high level of sales support and
marketing services throughout the company.
LAWSUIT RESOLUTION
Q. WHAT WAS THE OUTCOME OF YOUR LAWSUITS AGAINST FORMER AQUILA ENERGY EMPLOYEES
WHO MADE IMPROPER PAYMENTS WHILE ACQUIRING OIL AND GAS PROPERTIES FOR THE
COMPANY?
A. UtiliCorp and Aquila obtained judgements against and reached settlements with
substantially all defendants in the case during the second half of 1994. During
the course of the litigation, most of the funds improperly obtained by the
defendants were identified and accounted for. Approximately $7 million was
repaid to the company, including cash and property recovered from the defendants
and insurance proceeds. All counterclaims and third-party claims by the
defendants were dropped. Insurance proceeds received in July 1994 were $2
million, the limits of liability under the company's policy covering employee
dishonesty.
In 1992 the company took after-tax charges against earnings of $11.3
million due to this case of improper conduct. The net effect of the settlements
on the company's 1994 results from operations was a $2.4 million positive
adjustment after taking into account legal and related costs.
NATURAL GAS BUSINESSES
Q. DO YOU EXPECT GAS UTILITY REVENUES TO CONTINUE TO DECLINE? HOW DOES THIS
AFFECT THE COMPANY'S BOTTOM LINE?
A. Revenues from tariff sales of natural gas have gone down primarily because
large-volume customers have increasingly elected to purchase their gas directly
from producers and pay UtiliCorp only for transporting these volumes. This trend
is likely to continue, but it has little effect, if any, on the company's net
income. UtiliCorp earns about the same profit on gas transportation as it does
on tariff sales.
Q. WHAT IS THE EFFECT ON THE COMPANY'S UTILITY EARNINGS WHEN THE PRICE OF
NATURAL GAS GOES DOWN?
A. For our utility operations, a drop in gas prices lowers gas revenues but has
no effect on income. Changes up or down in the cost of gas are passed through to
the customer.
Q. HAS PERFORMANCE OF THE CENTRALIZED NATURAL GAS PURCHASING OPERATION MET YOUR
ORIGINAL EXPECTATIONS?
A. Yes. The Omaha-based gas supply operation was formed in mid-1993 in response
to the Federal Energy Regulatory Commission's Order 636. The Order shifted much
of the responsibility for gas supply from pipeline companies to distribution
utilities. UtiliCorp manages the acquisition of approximately 300 billion cubic
feet of gas per year for its retail distribution operations at a cost of more
than $500 million. Carrying out this purchasing from a centralized facility
gives all our gas operations access to an expanded interstate pipeline network
and helps them compete as low-cost providers.
UTILICORP
10
<PAGE>
During both the 1993 and 1994 winter heating seasons, UtiliCorp Gas Supply
Services performed very well securing volumes of natural gas for more than
750,000 end-use customers. Even when some of our gas territories experienced
periods of record or near-record peak demand, the gas supply team's flexibility
designed for the new deregulated environment minimized costs to customers and
enabled the company to avoid supply shortages and involuntary curtailment of
service.
Q. WHY DID UTILICORP WANT TO BUY AN INTRASTATE NATURAL GAS PIPELINE SYSTEM IN
EASTERN MISSOURI?
A. The $75 million acquisition of a 218-mile intrastate gas pipeline system fits
very well with UtiliCorp's existing operations in Missouri. The purchase was
completed in January 1995. UtiliCorp serves more than 40,000 gas distribution
customers elsewhere in the state, and the pipeline system provides the company
access to an alternative supply of gas for those customers. This will help keep
our prices competitive.
The purchase included the gas distribution system serving Fort Leonard
Wood, Missouri, home of a major military base in the central part of the state.
In 1994 the company began installing natural gas service for the town of Rolla,
located in the adjacent county. Since the intrastate pipeline extends east from
near Fort Leonard Wood all the way to the St. Louis area, it provides a base
from which UtiliCorp can provide distribution lines to other towns in eastern
Missouri that are currently without gas service.
Q. HOW DOES THE BROAD STREET OIL & GAS ACQUISITION FIT WITH UTILICORP'S OTHER
GAS MARKETING ACTIVITIES?
A. The acquisition of Broad Street Oil & Gas in January 1995 strengthened
UtiliCorp's customer base in commercial gas marketing, an important step in
carrying out the company's new national marketing strategy. Broad Street serves
more than 10,000 commercial customers in nine states, making it an ideal fit
with UtiliCorp's plans for aggressive growth in deregulating segments of the
energy market.
Prior to the acquisition, UtiliCorp was already marketing gas to
commercial customers in six states and, through Aquila Energy, to industrial and
wholesale customers in 45 states.
COMMON STOCK AND DIVIDENDS
Q. WHAT IS THE COMPANY'S DIVIDEND POLICY? WILL UTILICORP CONTINUE TO INCREASE
THE DIVIDEND ON ITS COMMON STOCK?
A. Over the past 10 years, UtiliCorp has achieved one of the strongest records
of dividend growth in the utility industry. With 12 increases, cash dividends
paid per year have gone up 121 percent. Management remains committed to
providing prudent dividend growth in the future. At the same time, it intends to
keep the dividend payout ratio (dividends divided by earnings per share) from
reaching a level that financial analysts consider too high during a time of
increasing competition. Management will continue to recommend that the board of
directors increase the common dividend rate periodically but at a pace that is
somewhat slower than growth in earnings per share.
Q. IS THERE A WAY I CAN BUY SHARES OF UTILICORP COMMON STOCK DIRECTLY FROM THE
COMPANY?
A. Yes. In February 1995 UtiliCorp introduced an expanded Dividend Reinvestment
and Common Stock Purchase Plan. Through the plan individuals can purchase their
first shares of UtiliCorp common stock directly from the company without paying
brokerage fees. The plan requires a minimum first-time purchase of $250.
Additional purchases through the plan may be made on a monthly basis with a
minimum contribution of $50 and a maximum of $10,000 per month. Plan
participants may also elect to reinvest all or some of their quarterly dividends
at a 5 percent discount.
Other options available through the new plan are direct drafting of your
checking or savings account to make monthly purchases; direct deposit of
dividend checks; safekeeping of certificate shares; Individual Retirement
Account registration and gift transfer notification certificates.
For more information about direct purchase or any of the other plan
features, call Shareholder Relations toll-free at (800) 487-6661, or (816)
421-6600.
RESHAPING THE COMPANY
Q. WHAT ARE THE FOUR NEW BUSINESS GROUPS THAT WERE CREATED IN 1994 AND HOW DO
THEY SUPPORT THE NEW NATIONAL STRATEGY?
A. The core businesses of UtiliCorp have been reconfigured to position them for
an increasingly competitive environment. The new structure provides both
operating and strategic advantages that will help the company keep its costs as
low as possible and serve its customers with a broad range of interrelated
energy products and services.
As the company launches its national strategy, it is now organized along
functional rather than geographic lines. This integrates all of UtiliCorp's U.S.
distribution utilities under a single business group, for example, rather than
seven separate operating divisions. The change provides ways to reduce costs and
increase responsiveness to the customer.
UTILICORP
11
<PAGE>
[Graphic]
UTILICORP
ENERGY DELIVERY
UTILICORP
ENERGY RESOURCES
UTILICORP
POWER SERVICES
UTILICORP
MARKETING SERVICES
FOUR PARTS IN ONE WHOLE
The realignment of UtiliCorp's principal businesses into four groups is bringing
opportunities to become more efficient, more competitive, and more focused than
ever on the customer.
<PAGE>
The four new business groups formed by UtiliCorp in 1994 are described
briefly below.
UTILICORP ENERGY DELIVERY. All of the company's electric and gas distribution
utilities in the U.S. now operate as part of UtiliCorp Energy Delivery, based in
Kansas City. Each of the states served is managed as a separate profit center--
Missouri, Kansas, Iowa, Nebraska, Colorado, Minnesota, Michigan and West
Virginia.
UtiliCorp Energy Delivery has approximately 348,000 electric customers and
780,000 gas customers. Its operations do not include West Kootenay Power, the
company's Canadian subsidiary. Creation of UtiliCorp Energy Delivery better
enables all the company's distribution utilities, including West Kootenay Power,
to share improvements in efficiency, customer service and technology.
UTILICORP POWER SERVICES. All of UtiliCorp's electric supply businesses in the
U.S., including the generation and transmission assets of the Missouri Public
Service and WestPlains Energy divisions, are now part of UtiliCorp Power
Services.
Based in Kansas City, this group operates utility generating plants with a
total capacity of 1,573 megawatts, located in Missouri, Kansas and Colorado. It
also includes the UtilCo Group subsidiary, an independent power producer with
interests in 16 generating projects in six states and Jamaica.
Besides the company's own distribution utilities, customers of UtiliCorp
Power Services include other utilities, municipalities, and large industrial
users of wholesale bulk power.
UTILICORP ENERGY RESOURCES. This business group, which includes all of the
operations of the Aquila Energy subsidiary, is the wholesale/resale gas
marketing and supply unit for UtiliCorp's non-regulated business activities. It
also includes Aquila's gas and oil properties, pipelines and gas processing
operations and its marketing of gas to industrial, wholesale and other large
customers across most of the U.S. and in parts of Canada.
Another part of UtiliCorp Energy Resources is the new Aquila Power
subsidiary, which started up the company's nationwide electricity marketing
business in January 1995. UtiliCorp Energy Resources is headquartered in Omaha
and has offices in Houston, San Antonio and Tulsa.
UTILICORP MARKETING SERVICES. In support of the company's national strategy and
competitive focus, UtiliCorp Marketing Services manages the EnergyOne nationwide
brand of products and services and provides sales and marketing support
throughout the company.
Based in Kansas City, this group develops products, services and programs
that position the company as the customer's preferred energy supplier. It also
manages specific marketing strategies for five market segments--large key
accounts, residential, commercial, wholesale and resale, and large power
generators.
Q. HAS CREATION OF THE FOUR NEW BUSINESS GROUPS MADE IT NECESSARY FOR UTILICORP
TO MAKE OTHER CHANGES IN THE WAY IT DOES BUSINESS?
A. Yes. To be as competitive as possible, it is critical that the company find
ways to improve the quality and efficiency of both operating and support
functions throughout UtiliCorp. Special teams of employees are working full-time
to examine specific opportunities to streamline, integrate or redesign the way
things are done.
Everything from running a generating station to producing financial reports
is covered by this review process. The goal is to do everything we do in less
time, at lower cost, with higher quality.
Q. WITH SO MANY CHANGES TAKING PLACE AT THE COMPANY, WHAT STEPS HAS MANAGEMENT
TAKEN TO ENSURE THAT EMPLOYEES ARE "ON BOARD" AND SUPPORTING THE NEW STRATEGY
EFFECTIVELY?
A. Actually, many of the changes in how the company does business are the result
of ideas generated by teams of employees who were asked to reexamine everything
we do. The strategic initiatives that resulted formed the basis for
organizational realignments and improvements in business processes and
procedures being implemented in 1995.
The "people factor" has been a key element in UtiliCorp's success, and will
continue to be. Employees' enthusiasm and understanding of each part of our new
strategy is a major force behind its implementation. Senior management started
off 1995 with a series of meetings with employees around the country to share
their vision of the future and personally answer questions about the changes
taking place.
Q. HOW HAVE THE DEMANDS OF LAUNCHING YOUR NEW STRATEGY AFFECTED UTILICORP'S
MANAGEMENT STYLE?
A. There has been a marked change in management style over the past two years as
the groundwork has been laid for becoming the nation's first national utility.
Teams in various forms bring flexibility and innovation. The work environment is
more informal but also has more intense focus on strategic results.
Since becoming a national utility means being able to compete as the
low-cost provider of energy, new efficiencies
UTILICORP
13
<PAGE>
are continually being sought both at headquarters and at field locations. Also,
a greater sales and marketing orientation is seen throughout the company as the
excitement and opportunity of capturing new markets and new customers becomes
apparent to employees at all levels.
Q. WHAT EQUIPS UTILICORP'S MANAGEMENT WITH THE ABILITY TO CARRY OUT ITS
AMBITIOUS PLANS TO BECOME THE FIRST NATIONAL UTILITY IN AMERICA?
A. In addition to extensive experience operating electric and gas utilities,
UtiliCorp's managers have been successful with a decade of expansion, have
operated major non-regulated businesses since 1986, and have fostered an
entrepreneurial spirit among the company's employee-owners.
Today, UtiliCorp's senior management team includes men and women who have
dealt with the effects of deregulation in other industries, such as airlines,
financial services and telecommunications. The company is equipped to redefine
the way utilities market energy by being among the first to recognize and enter
new, emerging market segments.
ELECTRIC BUSINESSES
Q. IS UTILICORP CURRENTLY BUILDING ANY NEW ELECTRIC GENERATING CAPACITY?
A. The company's integrated resource plan calls for the addition of 141
megawatts of new generating capacity at Pueblo, Colorado. Currently an
application is pending which would authorize construction of a new facility to
begin operation in 1998. The alternative of purchasing additional power from
another utility under long-term contract will be considered only if the
purchased power would be more economical over the long term for our Colorado
customers.
Q. DOES THE AQUILA ENERGY SUBSIDIARY HAVE THE NEEDED EXPERTISE TO MARKET
ELECTRICITY?
A. Yes. The same skills, business structure and support systems that have
enabled Aquila to succeed in marketing natural gas nationally since 1986 will be
drawn on as the company launches Aquila Power Corporation for nationwide
marketing of electricity in 1995.
Aquila Power will market electricity produced by others to large-volume,
wholesale customers such as utilities and municipalities. As the first power
marketer affiliated with both a gas marketer and an electric utility, it has a
competitive advantage. It will be able to capitalize on UtiliCorp's extensive
expertise in the electric business as well as in natural gas.
Q. WHY DID UTILICORP MOVE TO OPEN ITS ELECTRIC TRANSMISSION LINES TO USE BY
OTHER COMPANIES?
A. The company's filing in late 1994 to provide open access was intended to
encourage other utilities to open their transmission systems so that a broader
market for power in the U.S. will continue to develop. UtiliCorp expects to
compete effectively in such a market because the company offers highly reliable
service at competitive prices and has been preparing over the past 10 years for
a more fully deregulated environment.
The Federal Energy Regulatory Commission gave UtiliCorp's open access
application conditional approval in January 1995. This enables others to access
the company's 4,300 miles of electric transmission systems in Missouri, Kansas
and Colorado using a variety of pricing structures, depending on the exact
services used.
INTERNATIONAL ACTIVITIES
Q. DOES UTILICORP PLAN TO MAKE FURTHER ACQUISITIONS OR INVESTMENTS OVERSEAS? IN
WHICH COUNTRIES?
A. We are seeking growth opportunities in a number of foreign countries, but our
track record shows we maintain a methodical approach to overseas investment.
Operating in other countries increases our costs and requires adapting to
differences in culture and type of government. Since 1987, our policy has been
to expand in English-speaking countries.
Today we have operations or business interests in Canada, the United
Kingdom, New Zealand and Jamaica. We're also looking at opportunities in
Australia. In the future, opportunities may also demand that we consider Latin
America and parts of Asia. The one thing that will govern our choices in
international business is bottom line profitability.
Q. WHAT FACTORS MADE IT ATTRACTIVE TO INVEST IN THE JAMAICA POWER PLANT PROJECT?
A. Like UtilCo Group's other independent power projects, the Jamaica project is
considered low-risk because it will use a proven technology and sell its
electricity output under a long-term contract. The slow-speed diesel-powered
plant is expected to supply more than 10 percent of Jamaica's electricity needs
when it begins commercial operation in 1996.
The facility will sell its electric capacity and output to Jamaica Public
Service Company, a government-owned utility, under a 20-year contract.
UTILICORP
14
<PAGE>
[Graphic]
ANOTHER WAY TO LOOK AT IT
UtiliCorp's electric and gas distribution utilities serve more than 1.2 million
direct customers. Counting the energy redistributed by its wholesale
customers such as municipalities and other utilities the company reaches
about 22 million customers.
<PAGE>
1994 UTILICORP COMMON STOCK PERFORMANCE
[Line Graph]
S&P 500 down 1.5%
S&P Utilities down 13.0%
UCU down 16.5%
DJ Utilities down 20.8%
IMPORTANT 1995 DATES FOR SHAREHOLDERS
<TABLE>
<CAPTION>
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
-----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
DIVIDENDS (a)
Declaration Dates
Dividends are declared by the board of directors on: Feb. 1 May 2 Aug. 2 Nov. 1
-----------------------------------------------------------------------------------------------------------------------
Record Dates
To qualify for a dividend, shares must be recorded by: Feb. 17 May 19 Aug. 18 Nov. 17
-----------------------------------------------------------------------------------------------------------------------
Payment Dates (b)
Preference dividend checks should be received on: March 1 June 1 Sept. 1 Dec. 1
Common dividend checks should be received on: March 12 June 12 Sept. 12 Dec. 12
-----------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------
DIVIDEND REINVESTMENT (c)
Common Dividends Reinvested
Dividends for Plan participants are reinvested by
the company with a 5% discount on: March 12 June 12 Sept. 12 Dec. 12
-----------------------------------------------------------------------------------------------------------------------
Optional Cash Payments (c)
For the purchase made on the 12th of each month, Jan. 11 April 11 July 11 Oct. 11
First Chicago Trust Company of New York Feb. 10 May 11 Aug. 11 Nov. 10
must receive optional cash payment by: March 10 June 9 Sept. 11 Dec. 11
-----------------------------------------------------------------------------------------------------------------------
Quarterly Statement of Account
Statements for Plan participants are mailed: Late March Late June Late Sept. Late Dec.
-----------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------
ANNUAL MEETING
Convenes at 10:00 a.m. at Bartle Hall's Grand Hall,
301 West 13th Street, Kansas City, Missouri, on: May 3
-----------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------
<FN>
(a) DECLARATION OF DIVIDENDS, DIVIDEND RATES AND THE DATES SHOWN ARE SUBJECT TO
THE DISCRETION OF DIRECTORS OF UTILICORP UNITED. DATES PROVIDED HAVE BEEN
PREPARED ASSUMING PAST PATTERNS WILL CONTINUE. HOWEVER, THE COMPANY DOES
NOT AND CANNOT MAKE ANY ASSURANCES THAT ANY OR ALL OF THE EVENTS LISTED
WILL OCCUR ON DATES SHOWN, IF AT ALL. UTILICORP RESERVES THE RIGHT TO
AMEND, SUSPEND OR TERMINATE THE DIVIDEND REINVESTMENT AND COMMON STOCK
PURCHASE PLAN AT ANY TIME. PLAN PARTICIPANTS WILL BE NOTIFIED OF ANY
CHANGES IN WRITING.
(b) IF YOU DON'T RECEIVE YOUR DIVIDEND CHECK ON THE PAYMENT DATE, PLEASE ALLOW
REASONABLE TIME FOR POSTAL DELAYS BEFORE INQUIRING.
(c) PLEASE REFER TO THE LATEST PROSPECTUS OF THE DIVIDEND REINVESTMENT AND
COMMON STOCK PURCHASE PLAN DATED FEBRUARY 16, 1995. TO REQUEST A PROSPECTUS
AND AN ENROLLMENT CARD, CALL TOLL-FREE IN THE U.S. AND CANADA:
(800) 487-6661.
</TABLE>
UTILICORP
16
<PAGE>
EMPLOYEE OWNERSHIP
OUR EMPLOYEES' SENSE OF OWNERSHIP AND PARTICIPATION IN THE COMPANY'S SUCCESS HAS
BEEN AN IMPORTANT FACTOR IN UTILICORP'S RECORD OF INNOVATION AND GROWTH. THE
COMPANY HAS SEVERAL PROGRAMS IN PLACE TO ENCOURAGE EMPLOYEES TO ACQUIRE AND HOLD
SHARES OF ITS COMMON STOCK. AT THE END OF 1994, ABOUT 95 PERCENT OF UTILICORP'S
4,683 EMPLOYEES WERE SHAREOWNERS, HOLDING APPROXIMATELY 14 PERCENT OF THE TOTAL
SHARES OUTSTANDING. THIS HIGH PROPORTION OF EMPLOYEE OWNERSHIP IS ONE OF THE
MANY WAYS UTILICORP STANDS OUT AMONG UTILITY COMPANIES.
TO RECOGNIZE EMPLOYEES WHO HAVE ACHIEVED AN ESPECIALLY SIGNIFICANT LEVEL OF
OWNERSHIP IN RELATION TO THEIR SALARY LEVEL, THE COMPANY HAS CHOSEN TO GRANT
THE TITLE "UTILICORP PARTNER." THE INDIVIDUALS LISTED BELOW WERE NAMED PARTNERS
IN 1993 AND 1994.
<TABLE>
<S> <C> <C> <C>
Daniel M. Akers Russell Feller Mary Lee Lyle James Sisung
David R. Akers David Fenrick Carol Lyon Charles Smock
Paul Allerton Robin Frank Thomas Markstrom Jerry Sopher
Phillip Allgood August Froehlich Suzanne Maurer Lawrence Staab
Dennis Ambrose Frank Gessner Thomas Maus James Staub
Larry Ankney Deborah Girdwood John Maxson Kenneth Stegall
Verle Ayres Dennis Greashaber Melvin McGrew Craig Strehl
Diane Bailey Keith Green Lois McIntire Mary Stepp
Larry Bailey Robert K. Green James Menck Bernard Stone
William Bailey Richard C. Green, Jr. Luverne Meyer Leslie Stotz
Gina Baker Douglas Greifendorf James Miller Arthur Stough
John Baker John Hall Loretta Millstead Roger Stout
Arthur Barr Jr. Robert Hall Paula Miracle Marvin Strauss
Allen Barron Lynn Hamlet David Morris Duane Strong
Bruce Bartlett Howard Hamlin Michael Moser John Strunk
Robert Beck Rodney Hamm Opal Naugle Shirley Swedlund
Ruth Behrens Mary Jo Hammontree Judith Ness Melvin Tacke
Douglas Bell Kenneth Hansen Rodney O'Brien John Teeter
Thomas Benore Charles Hauska William Ohm Kenneth Thomas
Ruth Berglund Leroy Havener Don Ohrenberg Charles Tielbur
Edythe Bolthouse Rebecca Heeres Serena V. Oliphant Henry Turner
Joseph Braden Arlie Heisterberg David Otter Penelope Tvrdik
James Brook Ronald Herr John Owens Michael Tylutki
Pauline Broom Mary Ann Herrell-Boyd John Palincsar Donald Vance
John Brown Michael Hertling William Parker Mark Vanden-Heede
Roy Burke Jr. Phyllis L. Hoppert Robert Popelar Allen R. Vanderboegh
A. G. Christenson David Howrigon Nancy Preucil Birney L. Vanderboegh
Sidney Clark Terry Hutchins Carolyn Price David Vergot
John Clasen Gail Isackson Gary Price David Volker
Howard Colgrove Richard Itteilag Herman Rast Karl Wagner
Nancy Colton Donald Jesseph William Raymond David Waldvogel
Michael Condry Theodore Johnson Richard Remold Thomas Walston
Elliott Connell David Johnson Barbara Rice Charles Wardell
William Cook William Keehner Deborah Richard Robert Warren
Ruth Cornelius Ronald Kieft John Richardson Burton Watkins
Jake Costanza Dennis Kinne Tim Richardson Bradley Watrous
Frank Costello Richard Kintigh Nolan Ridner Leroy Weathers
Karen Coury Denise Koern Donald Riffle Carol Weller
Robert Curtis Wesley Kosier Joyce Rinne S. Thomas Wertz
Lila Cushman Ronald Kreiger Charles Roelant Judy White
Allan Dancy Douglas Kubash John Royston Carol White
Glen Davis Timothy Kuehnlein Daniel Ruffner Darlene Whiteaker
Thomas Davis Randy Kull Patrick Ryan James Whitelow
Ted Dice Tina La Plante Margaret Salow Mary Wienberg
Thomas Disterheft Ted Ladd Judith Samayoa Julian Wildrom
John Donihue Marlene Larson John Sawyer Jr. David Wilson
Robert Dye Harriet Lewallen S. F. Schiermeyer Bradley Wiltse
James Elbel Karen Loomis Barbara Schultz Dale Wolf
Donna Elliott Lawrence Loring Jo Ann Shackelford Kirby Woods
Kathryn Ellis Francis Losinski Harold Shigley Carol Yeager
Jon Empson John Luck Dean Shook Cheryl Zatko
Tom Esterline Myron Lueck Russell Shreeves Marilyn Zimmerman
Robert Fedewa Willis Lutes Arnold Sikorski John Zinner
</TABLE>
UTILICORP
17
<PAGE>
[Graphic]
REGULATED OPERATIONS
Electric
Gas
Combination
[Graphic]
NON-REGULATED OPERATIONS
AQUILA ENERGY:
Marketing Area
Production
Pipelines
Processing Plants
UTILCO GROUP:
Power Projects
[Graphic]
NEW ZEALAND
UTILICORP N.Z., INC.:
Electric Operations
[Graphic]
UNITED KINGDOM
UTILICORP U.K., INC.:
Gas Marketing Area
[Graphic]
JAMAICA
UTILCO GROUP:
Power Project
<PAGE>
OPERATIONS & FINANCE
KEY EVENTS OF 1994
- Consolidated net income in 1994 was $94.4 million or $2.08 per common
share, a 9.3% and 6.7% increase, respectively, over 1993 results of $86.4
million net income or $1.95 per share.
- The company launched a new strategy in December designed to make UtiliCorp
the first truly national utility in the U.S. The plan includes EnergyOne
-SM-, a unified brand name under which the company's products and services
will be marketed nationwide.
- The UtilCo Group subsidiary earned $6.4 million, its best year ever. It
earned $3.2 million in 1993.
- The quarterly common dividend was increased 2.4% in August to $.43 per
share from $.42. The annualized dividend rate is now $1.72.
- UtiliCorp completed its $23 million acquisition of a Kansas gas
distribution system from NorAm Energy Corp. in late September. The system
has 22,000 customers.
- The company agreed to acquire a Missouri intrastate gas pipeline system
from Edisto Resources Corporation for $75 million. This cash purchase was
completed in January 1995.
- In August, UtiliCorp agreed to acquire minority stakes in Power New Zealand
Limited and Energy Direct Corporation Limited, the second and fourth
largest electric distribution utilities in New Zealand in terms of
customers. These investments are expected to be completed in 1995.
- UtilCo Group agreed in October to become an equity partner in a 60-megawatt
electric generating project in Kingston, Jamaica for approximately $11
million.
- In December UtiliCorp agreed to acquire Broad Street Oil & Gas, a natural
gas marketing company serving approximately 10,000 commercial customers in
nine states. The purchase was completed in January 1995.
- In January 1995, Aquila Gas Pipeline Corporation purchased Tristar Gas
Company for $16.3 million cash. Tristar gathers, processes and markets
natural gas.
- The new Aquila Power subsidiary received conditional approval in January
1995 from the Federal Energy Regulatory Commission to market on a
nationwide basis electricity produced by others.
OVERVIEW
EXCEPT WHERE NOTED, THE FOLLOWING DISCUSSION REFERS TO THE CONSOLIDATED ENTITY,
UTILICORP UNITED INC., INCLUDING ITS THREE OPERATING SEGMENTS: ELECTRIC
OPERATIONS, GAS OPERATIONS AND ENERGY RELATED BUSINESSES. THE LATTER IS THE
CONSOLIDATED OPERATIONS OF AQUILA ENERGY CORPORATION (AQUILA), A SUBSIDIARY.
SIGNIFICANT EVENTS AND TRENDS ARE PRESENTED WHICH HAVE HAD AN EFFECT ON THE
OPERATIONS OF THE COMPANY DURING THE THREE-YEAR PERIOD ENDED DECEMBER 31, 1994.
ALSO PRESENTED ARE FACTORS THAT MAY AFFECT FUTURE OPERATING RESULTS, FINANCIAL
POSITION AND LIQUIDITY. THIS DISCUSSION SHOULD BE READ IN CONJUNCTION WITH THE
COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND ACCOMPANYING NOTES.
UtiliCorp's 1994 net income, income from operations and earnings per share
improved compared to the same periods in 1993 and 1992. UtiliCorp's earnings
growth is primarily due to improved results of UtilCo Group and other
non-regulated businesses. In 1994, non-regulated businesses, including Aquila,
contributed approximately $25 million or 27% of total net income. In spite of
milder weather patterns, the company's utility businesses earned slightly more
than in 1993 and well above 1992 results.
UTILICORP
19
<PAGE>
ELECTRIC OPERATIONS
THE COMPANY'S ELECTRIC SEGMENT INCLUDES THE ELECTRIC OPERATIONS OF MISSOURI
PUBLIC SERVICE, WEST KOOTENAY POWER, WEST VIRGINIA POWER AND WESTPLAINS ENERGY.
<TABLE>
<CAPTION>
Three-Year Review--Electric Operations YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $557.0 $546.9 $507.8
Expenses:
Fuel and purchased power 190.7 197.3 191.4
Other operating 101.9 97.8 90.4
Maintenance 38.8 38.5 32.7
Taxes, other than income taxes 50.4 48.0 42.2
Depreciation and amortization 49.9 45.9 41.7
----------------------------------------------------------------------------------------------------
Total expenses 431.7 427.5 398.4
----------------------------------------------------------------------------------------------------
Income from operations $125.3 $119.4 $109.4
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Identifiable assets $1,164.6 $1,162.0 $1,055.2
Capital expenditures 81.3 87.4 98.1
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Electric sales and transportation (MWH 000's) 10,825 10,609 9,753
Number of customers 426,414 417,884 410,826
Number of employees 1,838 1,948 1,906
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
</TABLE>
SEGMENT HIGHLIGHTS
Revenue and income from operations have increased 10% and 15%, respectively,
over the past three years. The increases are generally due to growth in the
number of customers, rate increases, higher coal plant efficiency and lower
purchased power costs over the three-year period.
REVENUES
Electric revenues for 1994 increased $10.1 million or 2% compared to 1993 due to
growth in the number of customers, which resulted in higher volumes. Revenues
increased $39.1 million or 8% in 1993 compared to 1992 due primarily to more
favorable weather patterns.
EXPENSES
Fuel and purchased power costs decreased significantly in 1994 compared to 1993
and were about the same as in 1992 despite an 11% increase in volumes since
1992. This decrease is the result of negotiating lower-priced contracts for
purchased power, coal and rail transportation. In addition, the company rebuilt
its 491-megawatt Sibley Generating Station and converted the plant to burn
low-sulfur coal. These projects enabled the plant to use coal more efficiently,
reducing fuel costs.
Other segment expenses increased from prior periods due to inflation,
greater depreciation related to additional plant investments and increased
revenue-related taxes.
CAPITAL EXPENDITURES
The 1995 capital budget is approximately $75 million. Electric construction
expenditures through 1999 are expected to average $98 million per year,
primarily for additional generating capacity and substations.
The company's largest capital project over the past several years was
rebuilding the Sibley Generating Station. This $70 million project was completed
in 1992 and added 20 years to the economic life of the facility. The renovation
cost only about 7% of what it would have cost to construct a new coal-fired
plant of similar capacity. During 1993, the company completed its three-year,
$45 million coal conversion project that enabled the Sibley plant to burn
low-sulfur coal and comply with environmental regulations.
ENVIRONMENTAL MATTERS
Completion of the Sibley coal conversion project has enabled the company to
comply with all environmental standards established by the Clean Air Act
Amendments of 1990 without installing costly scrubbers. The company has secured
UTILICORP
20
<PAGE>
multiple contracts for low-sulfur western coal and related transportation
agreements.
OUTLOOK
Movements toward an increasingly competitive environment and regulatory
initiatives to address these changes dominate the headlines of today's electric
industry journals and publications. Various state commissions are considering
proposals that will change the traditional utility business including allowing
customers to choose their energy suppliers. These proposals are expected to
impact large industrial and commercial customers first and may eventually be
available to residential customers.
Passage of the National Energy Policy Act of 1992 reduced restrictions on
the operation and ownership of independent power producers and provided
wholesale suppliers increased access to electric transmission lines throughout
the United States. Although some of the reform proposals have been far-reaching,
regulatory reform will likely take many years to evolve. Nonetheless, the
company has initiated a plan to realign its business units to take advantage of
opportunities that are available now and expected in the future.
The company currently accounts for the economic effects of regulation in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," and
accordingly has recorded certain costs as regulatory assets in the financial
statements. The company expects that its rates will continue to be based on
historical costs for the foreseeable future. Changes to the company's regulatory
environment which result from competitive trends may require the company to
discontinue the provisions of SFAS No. 71 at some future date. If the company
discontinued applying SFAS No. 71, it would be required to make adjustments to
the carrying value of certain assets.
The company expects the current level of growth in the number of electric
customers and demand for power to continue over the next few years. Long-term
capacity plans, including a combination of purchased power, conservation and
load management, and construction are frequently updated. Additional generating
capacity is likely to be needed toward the end of this decade. In Colorado, the
company is evaluating various options to meet expected energy demand in the late
1990s, including building a 141-megawatt power plant.
<TABLE>
<CAPTION>
REVENUES: ELECTRIC
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 557.0
1993 546.9
1992 507.8
---------------------------------------------------------------------------
<CAPTION>
INCOME FROM OPERATIONS: ELECTRIC
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 125.3
1993 119.4
1992 109.4
---------------------------------------------------------------------------
<CAPTION>
HISTORICAL CAPITAL EXPENDITURES: ELECTRIC
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 81.3
1993 87.4
1992 98.1
---------------------------------------------------------------------------
SIBLEY REBUILDING COAL CONVERSION OTHER
<CAPTION>
ESTIMATED CAPITAL EXPENDITURES: ELECTRIC
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1999 78
1998 98
1997 123
1996 115
1995 75
---------------------------------------------------------------------------
</TABLE>
UTILICORP
21
<PAGE>
GAS OPERATIONS
THE COMPANY'S GAS SEGMENT INCLUDES THE GAS OPERATIONS OF MISSOURI PUBLIC
SERVICE, KANSAS PUBLIC SERVICE, PEOPLES NATURAL GAS, NORTHERN MINNESOTA
UTILITIES, MICHIGAN GAS UTILITIES AND WEST VIRGINIA POWER.
<TABLE>
<CAPTION>
Three-Year Review--Gas Operations YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $618.6 $686.1 $515.7
----------------------------------------------------------------------------------------------------
Expenses:
Gas purchased for resale 381.1 443.4 331.3
Other operating 113.7 115.7 91.7
Maintenance 8.8 8.8 7.8
Taxes, other than income taxes 23.1 23.9 18.9
Depreciation and amortization 30.1 28.6 24.4
----------------------------------------------------------------------------------------------------
Total expenses 556.8 620.4 474.1
----------------------------------------------------------------------------------------------------
Income from operations $ 61.8 $ 65.7 $ 41.6
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Identifiable assets $819.9 $716.9 $579.3
Capital expenditures 50.7 53.1 51.7
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Gas sales (BCF) 128 145 117
Gas transportation (BCF) 136 116 113
Number of customers 779,630 740,354 599,316
Number of employees 2,292 2,280 1,997
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
</TABLE>
SEGMENT HIGHLIGHTS
UtiliCorp acquired the Kansas and Nebraska gas systems of NorAm Energy Corp.
(formerly Arkla, Inc.) during the third quarter of 1994 and first quarter of
1993, respectively. Gas revenues increased 20% and income from operations
increased 49% over the past three years. In 1994 gas revenues and income from
operations decreased 10% and 6% compared to 1993, respectively. Revenues and
operating income were reduced by customers switching from tariff sales to
transportation sales, but this had no significant effect on net income.
REVENUES
Revenues and income from operations have increased significantly from 1992. This
is primarily the result of the NorAm gas property acquisitions and rate
increases in many of the company's jurisdictions. The acquired Nebraska property
contributed approximately $85.2 and $97.9 million in revenue in 1994 and 1993,
respectively. The acquisition, effective February 1, 1993, added approximately
124,000 customers. NorAm's Kansas property added $3.5 million in revenue in
1994. The acquisition, effective September 30, 1994, added approximately 22,000
customers.
Revenues are affected by changes in weather patterns and the cost of gas.
In 1994, weather was generally milder than in 1993. In addition, the gas cost
component embedded in the company's tariff rates decreased as gas prices
declined.
Rate increases have increased revenues and income from operations. The
additional revenues recover costs associated with ongoing pipeline replacement
programs, extension of service to new areas and other operating cost increases.
EXPENSES
The segment's principal operating expense is gas purchased for resale.
Variations in this expense result from the same factors that affect gas
revenues, discussed above. Changes in gas prices do not affect income from
operations. Generally, all gas price fluctuations are passed through to the
company's customers.
Other gas segment expenses have increased since 1992, reflecting primarily
the NorAm property acquisitions and the increase in gas plant in service over
the three-year period.
CAPITAL EXPENDITURES
Over the past five years, the company has had a program to replace older pipe to
improve system safety and reliability. This program will continue for the
foreseeable future. The expenditures are expected to be recoverable through
rates.
UTILICORP
22
<PAGE>
During the last three years, the company has also installed piping to
extend service to several towns in Iowa, Minnesota, Missouri and Kansas. The
company will continue to extend service to new locations as economic
opportunities arise.
The capital budget for 1995 provides $38 million for gas operations,
including pipe replacement and system extensions. Construction expenditures
through 1999 are expected to average $40 million per year.
ENVIRONMENTAL MATTERS
The company is in the process of investigating and testing various manufactured
gas sites either currently or previously owned by the company to determine
whether or not there is a need for environmental remediations. These are
discussed in Note 10 to the consolidated financial statements.
OUTLOOK
A new era of increased competition for the purchase and sale of natural gas
began in late 1993 with implementation of Order 636 of the Federal Energy
Regulatory Commission. The order significantly shifted gas supply responsibility
from traditional pipeline company sources directly to distribution utilities
like the divisions of UtiliCorp. The company's pipeline suppliers started to
seek recovery of costs from customers, including UtiliCorp, as a result of Order
636. As of December 31, 1994, the company has recorded a liability and a
deferred asset of $24.0 million related to these costs. The company expects to
recover all Order 636 costs from its customers through periodic tariff
adjustments.
UtiliCorp's consolidated gas supply center, organized in 1993 in response
to the opportunities created by Order 636, has performed extremely well
including during a period of record demand in January 1994. The gas supply
center procures the majority of the natural gas needed by our distribution
systems. It provides broader access to available pipeline systems, which helps
UtiliCorp secure natural gas at the lowest possible prices. See page 21 for
additional discussion relating to the effects of competition on the utility
business.
UtiliCorp's gas utilities will continue programs to upgrade their systems
and increase the overall efficiencies of their operations. These programs
benefit customers and enable gas operations to grow in a competitive
environment.
<TABLE>
<CAPTION>
REVENUES: GAS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 618.6
1993 686.1
1992 515.7
---------------------------------------------------------------------------
<CAPTION>
INCOME FROM OPERATIONS: GAS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 61.8
1993 65.7
1992 41.6
---------------------------------------------------------------------------
<CAPTION>
HISTORICAL CAPITAL EXPENDITURES: GAS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 50.7
1993 53.1
1992 51.7
---------------------------------------------------------------------------
<FN>
NEW TOWN PIPING PIPE REPLACEMENT OTHER
</FN>
<CAPTION>
ESTIMATED CAPITAL EXPENDITURES: GAS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1999 40
1998 39
1997 40
1996 42
1995 38
---------------------------------------------------------------------------
</TABLE>
UTILICORP
23
<PAGE>
PROVIDING SPACE TO GROW
Within the UtiliCorp family of businesses there is a wide range of products and
services available to customers, only a few of which are shown here. As
EnergyOne extends it marketing reach, the list will continue to expand.
[Graphic]
<PAGE>
ENERGY RELATED BUSINESSES
THE ENERGY RELATED BUSINESSES SEGMENT CONSISTS SOLELY OF THE CONSOLIDATED
OPERATIONS OF THE COMPANY'S AQUILA ENERGY SUBSIDIARY, INCLUDING 82%-OWNED AQUILA
GAS PIPELINE. AQUILA IS INVOLVED IN THE GATHERING, PROCESSING AND MARKETING OF
NATURAL GAS, THE ACQUISITION AND PRODUCTION OF GAS AND OIL RESERVES AND THE
EXTRACTION AND SALE OF NATURAL GAS LIQUIDS.
<TABLE>
<CAPTION>
Three-Year Review--Energy Related Businesses YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Gas and oil production $ 76.9 $ 74.8 $ 69.9
Gas gathering and processing 245.7 267.9 207.3
Gas marketing, net (a) 16.4 (4.1) (1.8)
----------------------------------------------------------------------------------------------------
Total revenues 339.0 338.6 275.4
----------------------------------------------------------------------------------------------------
Expenses:
Gas purchases 166.6 177.1 123.7
Other operating 67.7 61.1 57.2
Maintenance 1.7 2.7 1.8
Depreciation, depletion and amortization 59.6 60.8 57.0
Restructuring charge (b) -- 69.8 --
Unusual item--loss provision -- -- 17.7
----------------------------------------------------------------------------------------------------
Total expenses 295.6 371.5 257.4
----------------------------------------------------------------------------------------------------
Income (loss) from operations,
before minority interests $ 43.4 $(32.9) $ 18.0
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Gain on sale of subsidiary stock $ -- $ 47.8 $ --
Net income (loss) 9.3 10.7 (10.2)
Identifiable assets 717.1 604.2 662.0
Capital expenditures and investments 113.6 94.5 48.9
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Proven reserves (BCF) (c) 162 119 156
Production volumes (BCF) (c) 27 30 33
Natural gas throughput (BCF) 136 120 104
Pipelines operated (miles) 2,718 2,531 2,014
Natural gas liquids produced (MILLION GALLONS) 475 483 368
Marketing volumes (BCF) 366 504 580
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Number of employees 449 407 358
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
<FN>
(a) REVENUES ARE REPORTED NET OF GAS COST.
(b) INCLUDES WRITE-OFF OF $3.7 MILLION RELATED TO CERTAIN ASSETS OWNED BY THE
COMPANY ON BEHALF OF AQUILA.
(c) INCLUDES BARRELS OF OIL EXPRESSED AS GAS EQUIVALENT, ASSUMING 6,000 CUBIC
FEET OF GAS PER BARREL OF OIL.
</TABLE>
SEGMENT HIGHLIGHTS
In 1994, Aquila reported net income of $9.3 million. In 1993 and 1992, net
income (loss) was $10.7 million and $(10.2) million, respectively. The net
income (loss) in 1993 and 1992 reflects the effects of a pretax restructuring
charge of $69.8 million in 1993, a $47.8 million gain on sale of subsidiary
common stock in 1993 and a $17.7 million loss provision for improper payments by
former employees in 1992. The 1993 restructuring charge consisted primarily of a
disposition reserve related to unprofitable contracts, a charge for asset
impairment and other reserves. At December 31, 1994, the liability for
anticipated settlement costs associated with the remaining contracts was $11.9
million. During 1994 certain contracts were settled more favorably than
originally anticipated in 1993, resulting in a $5.4 million positive adjustment
to income from operations.
In 1994, the company settled with certain defendants in lawsuits filed as a
result of the discovery in 1992 of improper payments. These settlements and
insurance recoveries net of legal and related costs resulted in a favorable
adjustment to income from operations of $2.4 million.
UTILICORP
25
<PAGE>
REVENUES
Revenues have increased $63.6 million or 23% since 1992. Revenues were about the
same in 1994 as in 1993. Aquila's revenues are affected by change in the prices
of natural gas, oil and natural gas liquids. Revenue from gas gathering and
processing decreased $22.2 million or 8% in 1994 compared to 1993 due primarily
to a 13% decrease in natural gas prices and a 7% decline in natural gas liquid
(NGL) prices. A 13% increase in throughput partially offset the decline in
natural gas and NGL prices.
In 1993, gas gathering and processing revenues increased $60.6 million from
1992 due to increased natural gas prices and throughput and greater NGL
production. Changes in volumes relate to increases in third-party drilling
activity and well connections.
EXPENSES
Expenses decreased $75.9 million or 20% in 1994 compared to 1993 and increased
$38.2 million or 15% since 1992. The primary reason for the sharp decrease in
expenses in 1994 from 1993 is the $69.8 million restructuring charge recorded in
1993. Other operating expenses increased $6.6 million or 11% in 1994 compared to
1993 and increased $10.5 or 18% since 1992. The increases in operating expense
are due primarily to the higher number of employees and other payroll-related
costs stemming from expanded gas gathering and plant operations.
OUTLOOK
Over the past two years, Aquila's strategic objectives have focused on three
major business activities--gas marketing, gas and oil exploration, development
and production, and gas gathering and processing. In addition, Aquila is
preparing to apply its gas marketing expertise to related businesses. In
November 1994, Aquila filed an application with the Federal Energy Regulatory
Commission (FERC) to market on a nationwide basis electric power produced by
others. This was conditionally approved by the FERC in January 1995.
Competition in the gas marketing industry has increased in recent years,
resulting in lower margins as companies compete to obtain new customers and keep
existing ones. Realizing this trend, Aquila has focused on increasing its
operating efficiency and lowering the unit cost of energy sold. Aquila's
strategy is to compete nationally in the gas marketing industry and to grow
market share. The primary focus is on certain industrial and distribution
customers located on pipelines identified as strategic in the Northeast, Central
Midwest and California, while maintaining a national presence. Management
believes Aquila's marketing business is well positioned to successfully
implement this strategy.
Aquila's gas and oil production business continues its focus on exploratory
and development drilling. Aquila's gas and oil reserves at the end of 1994
totaled 162 BCF equivalent, a 36% increase over 1993. Aquila's exploration,
development and production capital expenditures for 1995 emphasize development
drilling, the acquisition of producing properties and, to a lesser extent, the
pursuit of exploratory drilling projects.
<TABLE>
<CAPTION>
REVENUES: ENERGY RELATED
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 339.0
1993 338.6
1992 275.4
---------------------------------------------------------------------------
<CAPTION>
INCOME FROM OPERATIONS: ENERGY RELATED*
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 43.4
1993 36.9
1992 35.7
---------------------------------------------------------------------------
<FN>
* BEFORE MINORITY INTERESTS AND BEFORE CHARGES ($69.8 MILLION RESTRUCTURING
CHARGE IN 1993 AND UNUSUAL LOSS PROVISION OF $17.7 MILLION IN 1992).
</FN>
<CAPTION>
MARKETING VOLUMES
---------------------------------------------------------------------------
BILLION CUBIC FEET (BCF)
---------------------------------------------------------------------------
<S> <C>
1994 366
1993 504
1992 580
---------------------------------------------------------------------------
<CAPTION>
PROVEN RESERVES
---------------------------------------------------------------------------
BCF EQUIVALENT
---------------------------------------------------------------------------
<S> <C>
1994 162
1993 119
1992 156
---------------------------------------------------------------------------
</TABLE>
UTILICORP
26
<PAGE>
Aquila Gas Pipeline (AGP), an 82%-owned subsidiary in the gas gathering and
processing business, foresees numerous growth opportunities resulting from
additional well connections on existing systems as well as through acquisitions.
A $28 million pipeline expansion project near Katy, Texas is expected to
substantially increase AGP's natural gas liquids production when completed in
mid-1995. In January 1995, AGP completed an acquisition of the gas processing,
gathering and marketing assets of Tristar Gas Company for $16.3 million cash.
AGP is confident that its reputation for providing quality, cost-competitive
services to producers will allow it to gather additional volumes of gas.
UTILCO GROUP
THE RESULTS OF OPERATIONS OF UTILCO GROUP, WHICH OWNS AND OPERATES INDEPENDENT
POWER PROJECTS, ARE REPORTED AS OTHER INCOME.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Equity in partnership earnings $ 18.8 $ 14.6 $ 14.4
Net income 6.4 3.2 5.3
Investment in partnerships 122.8 100.2 102.2
Share of project assets 379.8 363.1 346.5
Share of project liabilities* 291.8 282.9 273.7
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
Aggregate capacity (megawatts) 792 732 732
Projects operating commercially 15 15 15
Projects under construction 1 -- --
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
<FN>
* MAJORITY IS NON-RECOURSE TO UTILICORP.
</TABLE>
UtilCo Group contributed net income of $6.4 million in 1994. It reported
net income of $3.2 million in 1993 and $5.3 million in 1992. Equity in
partnership earnings increased 29% and 31% over 1993 and 1992, respectively. The
increase in equity in partnership earnings and net income from 1993 is due to
two projects selling more output than in 1993. In addition, UtilCo Group's
financial results include the full year of two new projects that began
operations in the fall of 1993 and late 1992.
The reduction in net income for 1993 was due primarily to an increase in
the corporate tax rate as a result of the Budget Reconciliation Act of 1993. See
Note 8 to the consolidated financial statements for further discussion.
UtilCo Group has equity ownership interests in 16 independent power
projects, 15 of which are in commercial operation. In October 1994, UtilCo Group
agreed to acquire an equity interest in a 60-megawatt electric generating
project to be built in Kingston, Jamaica. When it begins commercial operation in
1996, the $138 million facility will sell its electric capacity and output to
Jamaica Public Service Company under a 20-year contract. The company will hold a
21% interest in the project and expects to contribute approximately $11 million
in equity. Investments in additional projects are expected to be made over the
next five years.
Consistent with UtiliCorp's strategy of spreading risk, UtilCo Group has
invested in generating projects located in six states and one foreign country.
Each project uses traditional fuels and proven technologies, and is a
competitive, low-cost producer of wholesale power. The projects sell their
electric output under long-term contracts with terms ranging from 15 to 40
years. At the end of 1994, UtilCo Group had ownership interests in projects with
a total capacity of 792 MW. Its ownership interests ranged from 21% to 50%.
OTHER INCOME
Other income increased $3.7 million or 25% since 1992. In addition to UtilCo
Group, this increase is primarily due to the
UTILICORP
27
<PAGE>
earnings from UtiliCorp U.K., Inc., which owns interests in gas marketing
ventures in the United Kingdom, and from various gas marketing businesses
managed by the company's utility divisions. UtiliCorp U.K., Inc.'s net income
has increased significantly since its first year of operation in 1991.
Several of the company's utilities have undertaken various non-regulated
businesses in recent years. These are also reported as other income. Most of
these businesses have required minimal capital investment. The activities
include consumer appliance protection programs, gas and coal brokering, propane
distribution, meter reading and billing services, and water and wastewater
management for municipalities and other utilities in or near the company's
service areas.
Net income from utility division gas marketing has increased strongly since
1992, primarily due to dramatic growth in service fees generated from off-system
customers.
LIQUIDITY AND CAPITAL RESOURCES
The company's cash requirements arise primarily from its growth strategy,
electric and gas utility construction programs and the need to fund the
investments of Aquila. UtiliCorp's ability to attract the necessary financial
capital at reasonable terms is critical to the company's overall plan.
Acquisitions and investments have been initially financed with short-term debt
and later permanently funded with various long-term debt securities or common
equity, depending on market conditions.
During the three years ended December 31, 1994, $372.3 million in net
long-term capital was secured: $185.8 million through various issues of stock
and $186.5 million through long-term debt. Common shareholders' equity at the
end of 1994 was approximately 41% of capitalization including short-term debt
and current maturities of long-term debt.
The company has available various short-term credit programs to augment its
cash requirements. A primary source of short-term funds is commercial paper, for
which the company has programs aggregating $200 million. To support these
programs, the company has two revolving credit agreements (Agreements) with a
consortium of banks aggregating $400 million. The Agreements expire in December
1995 and December 1996, and allow the issuance of notes that bear interest at
rates based on the prime rate or various money market rates. As of December 31,
1994, there were no outstanding borrowings under these Agreements.
The company also has two accounts receivable sale programs. The level of
funding available from these programs varies depending on the level of eligible
accounts receivable, which fluctuates seasonally. Under these programs, up to
$205 million is available to reduce short-term debt. At December 31, 1994,
$117.6 million of customer accounts receivable had been sold. Cash requirements
include utility plant additions, dividends, and required redemptions of
long-term securities. In general, cash provided from operating activities funded
all of the company's capital additions and operating needs for existing
businesses during the three years ended December 31, 1994. External financing
was required during that period to fund acquisitions and investments.
Over the next five years cash provided from operating activities is
expected to meet anticipated cash requirements, excluding acquisitions and debt
retirements scheduled. In December 1995 the company's $125.0 million of 9.3%
Senior Notes become due. The company anticipates it will be able to pay this
obligation through operating cash flow or other financial resources available at
that time.
In August 1994, the board of directors increased the quarterly dividend to
common shareholders to $.43 per share from $.42. This increase is consistent
with the company's overall policy and is based on the company's financial
results and earnings outlook.
In February and April 1993, the company issued 4.8 million and .5 million
shares of common stock, respectively. The combined net proceeds of $144.7
million were used to reduce short-term debt incurred for construction and
acquisitions and for general corporate purposes.
During 1993, the company issued $125 million and $70 million of Senior
Notes and $18.8 million secured debentures. The Senior Notes have interest rates
of 8.0% and 6.0% and expire in 2023 and 1998, respectively. The proceeds of
these issues were used to fund a trust that assumed $63.5 million in Mortgage
Bonds, to reduce short-term debt and redeem preference stock, and for other
general purposes.
In August 1993, the company purchased and retired approximately $33.0
million of First Mortgage Bonds. These bonds were purchased at a premium and
replaced with short-term debt. An additional $13.1 million of First Mortgage
Bonds were retired in 1994.
In November 1994, the company issued $100 million of 8.45% Senior Notes,
due in 1999. The funds from this issue were used to reduce short-term debt.
UTILICORP
28
<PAGE>
ACQUISITIONS AND INVESTMENTS
In January 1995, the company acquired Broad Street Oil & Gas Company, a gas
marketing business based in Ohio, and AGP acquired Tristar Gas Company, a Texas
gas processing, gathering and marketing firm. These acquisitions will expand
UtiliCorp's presence in national gas marketing to commercial customers and AGP's
growth opportunities in Texas.
In September 1994, the company completed its $23.0 million acquisition of
Kansas gas distribution and selected transmission assets from NorAm Energy Corp.
(NorAm). The Kansas system serves about 22,000 customers in Wichita and
surrounding communities. In February 1993, the company completed its $106
million acquisition of NorAm's Nebraska gas distribution system serving
approximately 124,000 customers in 63 eastern Nebraska communities. Gas revenues
for the Nebraska and Kansas systems in 1994 were approximately $85.2 million and
$3.5 million, respectively.
In August 1994, the company entered into a relationship agreement with the
Auckland, New Zealand-based Power New Zealand Limited (PNZ). Under this
relationship, the company has agreed to serve as PNZ's "cornerstone" shareholder
by acquiring 20% of PNZ's shares for approximately $55 million. Under this
relationship, the company has also agreed to acquire PNZ's 18.35% interest in
Wellington, New Zealand-based Energy Direct Corporation Limited for
approximately $21 million. These investments are expected to be completed in
1995.
In February 1994, the company signed a definitive agreement to purchase a
218-mile intrastate gas pipeline system from Edisto Resources Corporation for
$75 million in cash. This acquisition includes the gas distribution system
serving Fort Leonard Wood, Missouri and a pipeline that crosses the Mississippi
River near St. Louis. The purchase was completed in January 1995. The systems
will be operated by UtiliCorp Pipeline Systems, a wholly-owned subsidiary of the
company. This acquisition strategically positions the company to serve customers
in eastern Missouri and the St. Louis area.
In July 1993, the company entered a joint venture arrangement with the
Waikato Electricity Authority in New Zealand. Under the arrangement, UtiliCorp
agreed to purchase a 33% interest in Waikato-based WEL Energy Group Ltd. (WEL).
UtiliCorp initially paid $2.7 million at closing and paid the remaining $17
million in February 1995.
In September 1994, UtiliCorp expressed interest in acquiring all or some of
the utility distribution properties of Columbia Gas System, Inc. Columbia
operates gas distribution utilities in five states and serves 1.5 million
customers. At this time management does not know if the proposal will be
accepted.
RISK MANAGEMENT
The company routinely uses financial instruments to mitigate volatility in the
prices of natural gas, natural gas liquids and oil. These financial instruments
are designated as hedges and as such, associated gains and losses are deferred
until the commodity being hedged is received or delivered. Using financial
instruments to mitigate price volatility also limits the company's ability to
benefit from favorable changes in those prices. The company does not hedge all
such exposures related to fluctuations in commodity prices and, as a result, the
operating results of the company's energy related businesses are subject, to
some extent, to commodity price fluctuations.
<TABLE>
<CAPTION>
REVENUES
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 1,514.6
1993 1,571.6
1992 1,298.9
---------------------------------------------------------------------------
<FN>
ELECTRIC GAS ENERGY RELATED
</FN>
<CAPTION>
INCOME FROM OPERATIONS BEFORE CHARGES*
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 230.5
1993 222.0
1992 186.7
---------------------------------------------------------------------------
<FN>
ELECTRIC GAS ENERGY RELATED
* $69.8 MILLION RESTRUCTURING CHARGE IN 1993 AND $17.7 MILLION UNUSUAL LOSS
PROVISION IN 1992.
</FN>
<CAPTION>
UTILITY PLANT ADDITIONS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 132.0
1993 140.5
1992 149.8
---------------------------------------------------------------------------
<CAPTION>
CASH FROM OPERATIONS
---------------------------------------------------------------------------
DOLLARS IN MILLIONS
---------------------------------------------------------------------------
<S> <C>
1994 203.5
1993 284.4
1992 166.3
---------------------------------------------------------------------------
</TABLE>
UTILICORP
29
<PAGE>
INCOME TAXES
The level of income tax expense during the three-year period fluctuated
generally with the level of pretax accounting income except for 1993. The
effective tax rate in 1993 was significantly affected by the gain on the sale of
subsidiary stock that is not taxable according to U.S. tax law. Additionally,
the passage of the Budget Reconciliation Act of 1993 increased the federal tax
rate. As a result of the Act, the company made a retroactive adjustment to
reflect the increase in the corporate tax rate from 34% to 35%, effective
January 1, 1993.
The rise in the tax rate increased 1993 income tax expense approximately
$4.0 million, or $.10 per average common share. Deferred income tax liabilities
from regulated operations were also increased. However, because it is
anticipated these additional taxes will be recovered through rates, a regulatory
asset was established and included in Deferred Charges and Other Assets in the
accompanying balance sheet. See Note 8 to the consolidated financial statements
for further discussion.
The company has available approximately $69 million of net operating loss
carryforwards and approximately $83.5 million of alternative minimum tax (AMT)
credits. The net operating loss carryforwards expire beginning in 2008 while the
AMT credits have an indefinite life.
EFFECTS OF INFLATION
In the next few years, the company anticipates that the level of inflation, if
moderate, will not have a significant effect on its operations or acquisition
activity.
SOURCES OF REVENUES
1994
[Pie Chart]
Electric 37%
Gas 41%
Energy related 22%
SOURCES OF INCOME FROM OPERATIONS
1994
[Pie Chart]
Electric 54%
Gas 27%
Energy related 19%
ELECTRIC SALES AND TRANSPORTATION VOLUME BY TYPE
1994
[Pie Chart]
Residential 32%
Commercial 24%
Industrial 24%
Other 20%
GAS SALES AND TRANSPORTATION VOLUME BY TYPE
1994
[Pie Chart]
Residential 27%
Commercial 14%
Industrial & transportation 58%
Other 1%
UTILICORP
30
<PAGE>
STRETCHING INTO THE FUTURE
UtiliCorp expects the "information superhighway" to play a key role in bringing
energy consumers the same sore of choice and cost savings that came about
through deregulation of long-distance telephone service.
[Graphic]
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------------------------
IN MILLIONS EXCEPT PER SHARE 1994 1993 1992
-----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Electric operations $ 557.0 $ 546.9 $ 507.8
Gas operations 618.6 686.1 515.7
Energy related businesses 339.0 338.6 275.4
-----------------------------------------------------------------------------------------------------------
Total revenues 1,514.6 1,571.6 1,298.9
-----------------------------------------------------------------------------------------------------------
Expenses:
Fuel used for generation 77.4 72.9 73.5
Power purchased 113.3 124.4 117.9
Gas purchased for resale 547.7 620.5 455.0
Other operating 283.3 274.6 239.3
Maintenance 49.3 50.0 42.3
Depreciation, depletion and amortization 139.6 135.3 123.1
Taxes, other than income taxes 73.5 71.9 61.1
Restructuring charge -- 69.8 --
Unusual loss provision -- -- 17.7
-----------------------------------------------------------------------------------------------------------
Total expenses 1,284.1 1,419.4 1,129.9
-----------------------------------------------------------------------------------------------------------
Income from operations 230.5 152.2 169.0
-----------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Long-term debt 89.1 89.2 88.9
Short-term debt and other interest 13.2 10.9 10.2
Gain on sale of subsidiary stock -- (47.8) --
Minority interests 2.8 .8 --
Other income, net (18.3) (16.8) (14.6)
-----------------------------------------------------------------------------------------------------------
Total interest charges and other 86.8 36.3 84.5
-----------------------------------------------------------------------------------------------------------
Income before income taxes 143.7 115.9 84.5
Income taxes 49.3 29.5 31.6
-----------------------------------------------------------------------------------------------------------
Net income 94.4 86.4 52.9
Preference dividends 3.0 6.9 6.9
-----------------------------------------------------------------------------------------------------------
Earnings Available for Common Shares $ 91.4 $ 79.5 $ 46.0
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
Weighted Average Common Shares Outstanding:
Primary 43.97 40.74 34.93
Fully diluted 45.18 44.27 35.75
Earnings Per Common Share:
Primary $2.08 $1.95 $1.32
Fully diluted 2.06 1.92 1.31
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
UTILICORP
32
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
-----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ASSETS
Utility Plant in Service:
Electric $1,578.7 $1,526.6 $1,428.0
Gas 954.6 896.3 746.0
-----------------------------------------------------------------------------------------------------------
2,533.3 2,422.9 2,174.0
Less--accumulated depreciation 923.0 865.0 767.2
-----------------------------------------------------------------------------------------------------------
Net utility plant in service 1,610.3 1,557.9 1,406.8
Construction work in progress 23.3 22.3 46.7
-----------------------------------------------------------------------------------------------------------
Total utility plant, net 1,633.6 1,580.2 1,453.5
-----------------------------------------------------------------------------------------------------------
Non-Regulated Property, Net:
Energy related 544.5 498.0 484.7
Non-regulated generating assets and other 236.8 183.6 164.4
-----------------------------------------------------------------------------------------------------------
Total non-regulated property, net 781.3 681.6 649.1
-----------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 67.2 55.9 9.2
Funds on deposit 44.8 14.4 9.5
Accounts receivable, net 144.1 158.0 177.9
Accrued utility revenues 71.5 76.6 66.3
Fuel inventory, at average cost 95.0 63.1 55.0
Materials and supplies, at average cost 39.3 38.7 38.2
Prepayments and other 51.9 31.4 30.5
-----------------------------------------------------------------------------------------------------------
Total current assets 513.8 438.1 386.6
-----------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets 182.4 150.6 63.6
-----------------------------------------------------------------------------------------------------------
Total Assets $3,111.1 $2,850.5 $2,552.8
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $906.8 $ 851.7 $ 661.1
Preference and preferred stock 25.4 83.9 95.1
Long-term debt, net 976.9 1,009.7 890.8
-----------------------------------------------------------------------------------------------------------
Total capitalization 1,909.1 1,945.3 1,647.0
-----------------------------------------------------------------------------------------------------------
Current Liabilities:
Current maturities of long-term debt 138.8 1.8 5.9
Short-term debt 182.4 70.0 230.9
Accounts payable 340.3 392.5 329.2
Accrued taxes 21.0 28.3 15.3
Accrued interest 22.1 20.1 16.1
Other 89.0 52.1 61.4
-----------------------------------------------------------------------------------------------------------
Total current liabilities 793.6 564.8 658.8
-----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Deferred income taxes 279.4 212.9 159.6
Investment tax credits 21.0 22.1 23.3
Minority interests 28.4 27.2 --
Other 79.6 78.2 64.1
-----------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 408.4 340.4 247.0
-----------------------------------------------------------------------------------------------------------
Commitments and Contingencies
-----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $3,111.1 $2,850.5 $2,552.8
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
UTILICORP
33
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31,
----------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS EXCEPT PER SHARE 1994 1993 1992
----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common Shareholders' Equity:
Common stock, authorized 100,000,000 shares, par value
$1 per share, 44,827,135 shares outstanding (42,021,160 at
December 31, 1993 and 35,421,598 at December 31, 1992) $ 44.8 $ 42.0 $ 35.4
Premium on capital stock 774.2 722.4 545.7
Retained earnings 107.0 93.4 81.5
Treasury stock, at cost (227,587 shares at December 31, 1994) (6.6) -- --
Currency translation adjustment (12.6) (6.1) (1.5)
----------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 906.8 851.7 661.1
----------------------------------------------------------------------------------------------------------------
Preference Stock, not mandatorily redeemable:
$2.05 series, 1,000,000 shares 25.0 25.0 25.0
----------------------------------------------------------------------------------------------------------------
Preference Stock, convertible and mandatorily redeemable:
$1.775 series (2,885,000 shares outstanding at December 31, 1993
and 2,976,116 at December 31, 1992) -- 58.5 60.7
----------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiary, retractable .4 .4 9.4
----------------------------------------------------------------------------------------------------------------
Long-Term Debt, net 976.9 1,009.7 890.8
----------------------------------------------------------------------------------------------------------------
Total Capitalization $1,909.1 $1,945.3 $1,647.0
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS EXCEPT PER SHARE 1994 1993 1992
----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common Stock:
Balance beginning of year $ 42.0 $ 35.4 $ 34.5
Issuance of common stock 2.8 6.6 .9
----------------------------------------------------------------------------------------------------------------
Balance end of year 44.8 42.0 35.4
----------------------------------------------------------------------------------------------------------------
Premium on Capital Stock:
Balance beginning of year 722.4 545.7 526.2
Issuance of common stock 51.8 177.1 19.2
Other -- (.4) .3
----------------------------------------------------------------------------------------------------------------
Balance end of year 774.2 722.4 545.7
----------------------------------------------------------------------------------------------------------------
Retained Earnings:
Balance beginning of year 93.4 81.5 91.8
Net income 94.4 86.4 52.9
Dividends on preference stock (3.0) (6.9) (6.9)
Dividends on common stock--$1.70 per share
in 1994, $1.62 in 1993, and $1.60 in 1992 (74.6) (67.1) (55.7)
Reissuance of common stock (3.2) (.5) (.6)
----------------------------------------------------------------------------------------------------------------
Balance end of year 107.0 93.4 81.5
----------------------------------------------------------------------------------------------------------------
Treasury stock, at cost (227,587 shares at December 31, 1994) (6.6) -- --
----------------------------------------------------------------------------------------------------------------
Currency Translation Adjustment (12.6) (6.1) (1.5)
----------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity $906.8 $851.7 $661.1
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
UTILICORP
34
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income $ 94.4 $ 86.4 $ 52.9
Adjustments to reconcile net income to net cash provided:
Depreciation, depletion and amortization 147.1 146.0 131.1
Gain on sale of subsidiary stock -- (47.8) --
Restructuring charge -- 69.8 --
Unusual loss provision -- -- 17.7
Deferred taxes and investment tax credits 65.4 (14.8) 14.8
Changes in certain current assets and liabilities,
net of effects of acquisitions and restructuring--
Funds on deposit (30.4) (4.9) (9.5)
Accounts receivable and accrued revenues 40.6 46.8 (54.5)
Accounts receivable sold (21.5) (10.9) 10.0
Fuel and materials (32.6) (7.6) (8.3)
Accounts payable (52.2) 13.9 56.2
Accrued taxes (7.3) 10.0 (21.9)
Other 18.4 11.4 (13.7)
Changes in other assets and liabilities, net (18.4) (13.9) (8.5)
----------------------------------------------------------------------------------------------------------------
Cash provided from operating activities 203.5 284.4 166.3
----------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Additions to utility plant (132.0) (140.5) (149.8)
Purchase of utility operations (28.2) (99.0) --
Sale of subsidiary stock -- 74.6 --
Investments in non-regulated generating assets (22.2) (28.8) (14.8)
Investments in energy related properties (113.6) (94.5) (48.9)
Other (24.5) (1.6) (15.8)
----------------------------------------------------------------------------------------------------------------
Cash used for investing activities (320.5) (289.8) (229.3)
----------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Issuance of common stock 2.8 178.8 20.0
Issuance of preference stock, net of retirements (6.8) (9.0) --
Treasury stock acquired (6.6) -- --
Issuance of long-term debt, net of premium paid 104.1 217.4 230.3
Retirement of long-term debt -- (99.8) (265.5)
Short-term borrowings (repayments), net 112.4 (160.9) 119.9
Cash dividends paid (77.6) (74.4) (62.6)
----------------------------------------------------------------------------------------------------------------
Cash provided from financing activities 128.3 52.1 42.1
----------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 11.3 46.7 (20.9)
Cash and cash equivalents at beginning of year 55.9 9.2 30.1
----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 67.2 $ 55.9 $ 9.2
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for--
Interest, net of amount capitalized $100.3 $ 94.5 $104.2
Income taxes 11.4 24.5 26.7
----------------------------------------------------------------------------------------------------------------
Liabilities assumed in acquisitions--
Fair value of assets acquired $ 35.9 $106.3 --
Cash paid for acquisitions 28.2 99.0 --
Liabilities assumed 7.7 $ 7.3 --
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
UTILICORP
35
<PAGE>
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of UtiliCorp United Inc. (the company)
include all operating divisions and all majority-owned subsidiaries. The
company's principal lines of business are electric and gas utility operations,
gas marketing, oil and gas production, gas processing and independent power
generation. The utility businesses operate in eight states and in Canada.
Natural gas is marketed in 45 states and the company's gas processing and
production facilities are in Texas and Oklahoma. In addition to U.S. and
Canadian businesses, the company has various investments in the United Kingdom
and New Zealand.
All significant intercompany accounts and transactions have been
eliminated. The energy related businesses segment reflects the operations of
Aquila Energy Corporation (Aquila) including its 82% owned subsidiary Aquila Gas
Pipeline Corporation (AGP). The results of operations of non-regulated business
units, principally UtilCo Group, and other non-regulated activities are included
in Other income, net, in the Consolidated Statements of Income.
The company's accounting policies conform to generally accepted accounting
principles which, in the case of the company's utility operations, consider the
impact of rate regulation.
Minority Interests. Minority interests represent the minority
stockholders' proportionate share of the stockholders' equity and net income,
primarily AGP. The company also owns majority interest in a gas marketing
company in the United Kingdom and an investment in a New Zealand electric
utility.
Regulation. The company's utility operations are subject to regulation by
various regulatory authorities. The company currently applies accounting
standards that recognize the economic effects of rate regulation and,
accordingly, has recorded regulatory assets related to the company's energy
generation, transmission and distribution operations. The total amount of
regulatory assets recorded at December 31, 1994, 1993 and 1992 approximates
$183.7, $154.2 and $63.6, respectively. The largest regulatory asset represents
receivables from customers for certain tax deductions which have been
flowed-through to the company's ratepayers. Regulatory assets represent
expected future revenue which will be recovered from customers through the
ratemaking process.
Utility Plant and Depreciation. Utility plant is stated at original cost.
Repair and maintenance costs are expensed as incurred. When property is
replaced, removed, or abandoned, its cost, together with the costs of removal
less salvage, is charged to accumulated depreciation.
For financial statement purposes, depreciation is provided on a straight-
line basis over the estimated lives of depreciable property by applying
composite average annual rates, ranging from 3.0% to 4.6%, as approved by
regulatory authorities.
Gas and Oil Properties. Gas and oil properties are accounted for using the
full cost method. Under the full cost method, all costs associated with gas and
oil property acquisition, exploration and development, including non-productive
costs, are capitalized. No gains or losses are recognized on the sale or
disposition of gas and oil properties, except for significant transactions.
The provision for depreciation, depletion and amortization is determined
using the units of production method over the estimated lives of the producing
properties based on estimated quantities of proved reserves. Amorization per
MCF equivalent averaged $1.44, $1.27 and $1.17 in 1994, 1993 and 1992,
respectively. The unamortized cost of gas and oil properties may not exceed the
future value of recoverable gas and oil reserves at current or contractual
prices, discounted at 10%.
Gathering, processing and other energy related property is depreciated
using a composite average annual rate of 4.0%.
Revenue Recognition. Revenues are recognized when the product or services
are delivered. Gas marketing revenues are included in the Energy Related
Businesses revenue caption on the Consolidated Statements of Income and are
based on the margin differential between the amount billed to the customer, the
related transportation cost and the price paid to the gas supplier on gas
volumes purchased and delivered during the period.
UTILICORP
36
<PAGE>
The table below presents gross marketing revenues and cost of gas for the
periods presented in the Consolidated Statements of Income:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------
<S> <C> <C> <C>
DOLLARS IN MILLIONS 1994 1993 1992
-------------------------------------------------------------------------------
Marketing revenue $613.2 $949.3 $984.7
Cost of gas 596.8 953.4 986.5
-------------------------------------------------------------------------------
Net revenue $ 16.4 $ (4.1) $ (1.8)
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
</TABLE>
Risk Management. As a producer and marketer of various commodities, the
company is exposed to price risk from fluctuating commodity prices. The company
utilizes various financial instruments to mitigate much of its exposure to
fluctuation in prices of natural gas, natural gas liquids and oil. These
financial instruments are designated as hedges of gas and oil production and
existing commitments and as such, gains or losses associated with these
financial instruments are deferred until the commodity being hedged is produced
or delivered.
Income Taxes. The company accounts for income taxes using the liability
method. Under this method, deferred tax assets and liabilities are determined
by applying tax regulations existing at the end of a reporting period to the
cumulative temporary differences between the tax basis of assets and liabilities
and their reported amounts in the financial statements.
Deferred investment tax credits are amortized over the lives of the related
properties.
No provision is made for U.S. income taxes on undistributed earnings of a
wholly-owned Canadian subsidiary ($48.4 million at December 31, 1994) because it
is management's intention to reinvest such earnings in Canadian operations.
Consolidated income before income taxes for the years ended December 31, 1994,
1993, and 1992 included $9.1, $10.7 and $13.8 million, respectively, from
Canadian operations.
Purchased Gas Adjustment and Energy Adjustment Clauses. The majority of
the company's revenues are subject to adjustment clauses. Changes in the cost
of purchased gas, fuel used for generation and purchased power to be recovered
are charged to expense during the period in which the recovery of costs is
included in revenues.
Cash Equivalents. Cash equivalents are defined as temporary cash
investments with a maturity of three months or less. As of December 31, 1994,
1993 and 1992, the company had cash of $57.0 million, $52.2 million and $15.7
million, respectively, held in the United Kingdom and Canada.
Earnings Per Common Share. Primary earnings per common share are computed
on the basis of the weighted average number of common shares outstanding.
Fully diluted earnings per common share assume conversion of convertible
subordinated debentures and convertible preference stock for the periods they
were outstanding and dilutive.
Currency Translation Adjustment. Financial statements of foreign
operations have been translated into U.S. dollars using applicable exchange
rates. Resulting translation adjustments increase or decrease common
shareholders' equity.
Reclassifications. Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1994
presentation.
UTILICORP
37
<PAGE>
NOTE 2: CORPORATE STRATEGY
The company is in the process of realigning its operations to take advantage of
changes in the company's business environment. To respond to these changes,
UtiliCorp is realigning its present structure into four business groups: Energy
Delivery will distribute energy to electric and gas utility customers; Power
Services will generate electric power and maintain related transmission
facilities; Energy Resources will market natural gas and electric power and
operate Aquila's other businesses; and Marketing Services will manage large
account sales, new product development and marketing services under the
EnergyOne -SM- brand.
In connection with the operational realignment, the company is currently in
the process of reviewing its key customer and administrative work practices. As
part of this realignment, it is anticipated that certain functions will be
centralized that may result in employee relocations, facility consolidations and
other related changes. Management expects long-term cost savings to result from
this realignment. Realignment costs incurred in the year ended December 31,
1994 were not significant.
In the fourth quarter of 1993, Aquila implemented a new business strategy
and recorded a $69.8 million charge against income ($45 million after tax) for
disposal of selected gas sales contracts, impairment of certain offshore assets,
and other restructuring costs. As of December 31, 1994, cash outlays associated
with the restructuring plan totaled approximately $17.1 million. Certain sales
contracts have been settled more favorably than originally anticipated in 1993,
resulting in a $5.4 million positive adjustment to income from operations. The
remaining liability of $11.9 million at December 31, 1994 relates primarily to
anticipated settlement costs associated with the remaining contracts.
In October 1993, AGP completed an initial public offering and sale of 5.4
million shares of common stock, representing approximately 18% of its stock.
Net proceeds of the offering approximated $74.6 million and were used to reduce
short-term debt incurred for working capital purposes. This transaction
resulted in a gain of $47.8 million, recorded as non-operating income in the
Consolidated Statements of Income. Consistent with U.S. tax laws, no income tax
expense was recorded related to this gain.
NOTE 3: UTILITY ACQUISITIONS
The excess of total acquisition costs over the aggregate regulated value of net
assets acquired to date is included in Utility Plant ($127.6 million, net of
$26.4 million in accumulated amortization at December 31, 1994) and is being
amortized on a straight-line basis over periods ranging from 15 to 35 years.
On January 5, 1995, the company completed the $75 million purchase of a
218-mile intrastate natural gas pipeline system in Missouri from Edisto
Resources Corporation.
On September 30, 1994, the company acquired the Kansas gas distribution and
selected pipeline properties of NorAm Energy Corp. (formerly Arkla, Inc.) for
$23.0 million. The Kansas system serves approximately 22,000 customers.
On February 1, 1993, the company paid $106 million to acquire a Nebraska
gas distribution system from NorAm Energy Corp., including $21 million in
working capital. The Nebraska system serves approximately 124,000 customers.
UTILICORP
38
<PAGE>
NOTE 4: NON-REGULATED PROPERTY
Aquila is involved in the gathering, processing and marketing of
natural gas, the acquisition and development of proven gas and oil reserves, and
the extraction and sale of natural gas liquids. Aquila's investment in
properties, including AGP's, is summarized below:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Property and investments:
Gas and oil properties $416.7 $337.2 $313.7
Gathering, processing and other 440.0 419.8 351.5
-----------------------------------------------------------------------------------------------------------------------------------
856.7 757.0 665.2
Less--depreciation, depletion and amortization 312.2 259.0 180.5
-----------------------------------------------------------------------------------------------------------------------------------
Net Property and Investments $544.5 $498.0 $484.7
-----------------------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
UtilCo Group is involved in the ownership and operation of facilities
in the independent and wholesale power generation market. Non-Regulated
Property, as reflected in the Consolidated Balance Sheets at December 31, 1994,
includes $133.5 million related to UtilCo Group's investments in partnerships
and a leveraged lease. UtilCo Group partnership investments are summarized
below:
<TABLE>
<CAPTION>
INVESTMENT DECEMBER 31, SHARE OF PRETAX EARNINGS
-----------------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS Ownership 1994 1993 1992 1994 1993 1992
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
UtilCo Group partnerships* 21% - 50% $122.8 $100.2 $102.2 $18.8 $14.6 $14.4
-----------------------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------------------
<FN>
*INVESTMENT EXCEEDS UTILCO GROUP'S INTEREST IN THE UNDERLYING PARTNERSHIP NET ASSETS. ACQUISITION AND TRANSACTION COSTS INCLUDED IN
THE INVESTMENT BALANCES ARE BEING AMORTIZED ON A STRAIGHT-LINE BASIS OVER THE REMAINING LIVES OF THE RELATED FACILITIES.
</TABLE>
Summarized combined financial information of unconsolidated equity investments
of UtilCo Group is presented below:
<TABLE>
<CAPTION>
DECEMBER 31, YEAR ENDED DECEMBER 31,
-------------------------------------------------------- ---------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992 DOLLARS IN MILLIONS 1994 1993 1992
-------------------------------------------------------- ---------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Assets Operating results
Current assets $115.7 $111.2 $ 89.5 Revenues $352.8 $313.1 $238.3
Non-current assets 855.5 881.0 858.9 Costs and expenses 299.7 269.2 199.2
-------------------------------------------------------- ---------------------------------------------------
Total assets $971.2 $992.2 $948.4 Partnership income $ 53.1 $ 43.9 $ 39.1
-------------------------------------------------------- ---------------------------------------------------
-------------------------------------------------------- ---------------------------------------------------
Liabilities and capital
Current liabilities $ 93.7 $ 92.3 $264.7
Non-current liabilities* 694.8 735.8 563.8
Partnership capital 182.7 164.1 119.9
--------------------------------------------------------
Total liabilities
and capital $971.2 $992.2 $948.4
--------------------------------------------------------
--------------------------------------------------------
<FN>
*MAJORITY IS NON-RECOURSE TO UTILICORP.
</TABLE>
UTILICORP
39
<PAGE>
NOTE 5: SHORT-TERM DEBT
At December 31, 1994, $182.4 million of short-term debt was outstanding,
comprised of notes issued under bank lines, commercial paper and other short-
term arrangements. Such borrowings had a weighted average interest rate of 6.2%.
In 1993 and 1992 the company's borrowings had a weighted average interest rate
of 3.51% and 4.21%, respectively.
The company has commercial paper programs aggregating $200 million. To
support these programs, the company has two revolving credit agreements
(Agreements) with a consortium of banks aggregating $400 million. The
Agreements, which expire in December 1995 and December 1996, also allow the
issuance of notes which bear interest at rates based on the prime rate or
various money market rates. The Agreements contain certain restrictive
covenants and the company pays an average annual commitment fee of .188% on the
unused portion of the Agreements. As of December 31, 1994, there were no
outstanding borrowings under these Agreements.
NOTE 6: LONG-TERM DEBT
The company's long-term debt is summarized below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
FIRST MORTGAGE BONDS:
Various, 9.92%*, due 1996-2008 $ 29.0 $ 36.1 $ 70.6
MORTGAGE BONDS:
Series 1, 9.875%, retired during 1993 -- -- 63.5
SENIOR NOTES:
9.30% Series, due December 1, 1995 125.0 125.0 125.0
6.0% Series, due April 1, 1998 70.0 70.0 --
9.21% Series, due October 11, 1999 50.0 50.0 50.0
8.45% Series due November 15, 1999 100.0 -- --
Aquila Southwest Energy 8.29% Series,
due September 15, 2002 100.0 100.0 100.0
8.2% Series, due January 15, 2007 130.0 130.0 130.0
10.5% Series, due December 1, 2020 125.0 125.0 125.0
9.0% Series, due November 15, 2021 150.0 150.0 150.0
8.0% Series, due March 1, 2023 125.0 125.0 --
SECURED DEBENTURES OF WEST KOOTENAY POWER:
10.37%*, due 1995-2023 54.0 57.9 41.2
SUBORDINATED DEBENTURES:
Various, 9.98%*, due 1995-2011 20.7 23.9 27.5
OTHER NOTES AND OBLIGATIONS 43.0 18.6 13.9
------------------------------------------------------------------------------------------
Total long-term debt (including current maturities) $1,115.7 $1,011.5 $896.7
------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------
<FN>
*WEIGHTED AVERAGE INTEREST RATE.
</TABLE>
The amount of long-term debt maturing in each of the next five years,
including sinking fund provisions, is as follows (in millions): 1995--$138.8;
1996--$15.0; 1997--$25.7; 1998--$95.1; and 1999--$165.2.
In November 1994, the company issued $100 million of 8.45% Senior Notes due
in 1999. The net proceeds of $99.5 million were used to reduce short-term debt
incurred for construction and acquisitions, and for general corporate purposes.
UTILICORP
40
<PAGE>
Substantially all of the domestic utility plant owned by the company is
subject to the lien of various mortgage indentures. The company cannot issue
additional mortgage bonds without directly securing the 6.0%, 8.45%, 8.2%, 9.0%,
and 8.0% Senior Notes equally as any mortgage bond issue. The company has no
plans to issue mortgage bonds in the near future.
The company executed an Indenture in 1990 (Indenture) for the issuance of
senior notes. Notes issued pursuant to the Indenture will be unsecured
obligations of the company and will rank on a parity with all other unsecured
and subordinate indebtedness of the company.
At December 31, 1994, 6.625% convertible subordinated debentures totaling
$12.2 million remained outstanding. The debentures can be converted into
approximately 515,000 shares of common stock, based on a conversion price of
$23.68, subject to an annual maximum limitation. The debentures are subordinate
to the prior payment, when due, of the principal and premium, if any, and
interest on all the company's debt outstanding, except debt that by its terms is
not senior in right of payment to the debentures.
NOTE 7: CAPITAL STOCK
As of December 31, 1994, the company was not restricted as to payment of cash
dividends.
The Board of Directors of the company (the Board) is authorized to
approve the issuance of up to 20 million shares of Class A common stock, $1.00
par value. No shares of Class A common stock are issued or outstanding.
In February 1995 the company registered 3 million shares of common stock
for a Dividend Reinvestment and Common Stock Purchase Plan. At December 31,
1994, there were 3,098,296 shares reserved for issuance under its Dividend
Reinvestment and Stock Purchase Plan, a Non-Employee Director Plan, and various
employee benefit and other plans.
Stock Awards and Stock Options. The company's Stock Incentive Plan
provides for the granting of common shares to certain employees as restricted
stock awards and as stock options.
Shares issued as restricted stock awards are held by the company until
certain restrictions lapse, generally on the third award anniversary. The
market value of the stock, when awarded, is amortized to compensation expense
over the three-year period.
Stock options granted under the Plan allow the purchase of common shares at
a price not less than fair market value at the date of grant. Options are
generally exercisable commencing with the first anniversary of the grant and
expire after 10 years from the date of grant.
The Board approved the establishment of an Employee Stock Option Plan in
1991. This Plan provides for the granting of up to 1 million stock options to
full-time employees other than those eligible to receive options under the Stock
Incentive Plan. Stock options granted under the Employee Stock Option Plan
carry the same provisions as those issued under the Stock Incentive Plan.
During 1992, options for 742,900 shares were granted to company employees. The
exercise price of these options is $27.3125. No options have been issued under
this Plan since 1992.
Restricted stock awards and stock options become exercisable for the
purchase or transfer of 216,795 shares in 1995, 14,474 in 1996 and 59,055 in
1997.
Stock options are summarized below:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------------------------------
SHARES 1994 1993 1992
-------------------------------------------------------------------------------
<S> <C> <C> <C>
BEGINNING BALANCE 1,284,833 1,193,437 345,284
Granted 202,350 239,091 988,404
Exercised (98,910) (128,564) (112,575)
Cancelled (31,950) (19,131) (22,676)
-------------------------------------------------------------------------------
ENDING BALANCE 1,356,323 1,284,833 1,198,437
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Option price $17.40 $17.40 $17.40
range at to to to
December 31 $31.63 $28.69 $28.69
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
</TABLE>
Mandatorily Redeemable Convertible Preference Stock. In February 1994, the
Board authorized the redemption of all outstanding shares of the $1.775 Series
Convertible Preference Stock. During the 1994 first and second quarters,
approximately 1.3 million and 1.5 million shares of the $1.775 stock were
converted into approximately 2.7 million shares of common stock. The remaining
shares, approximately 1 million, were redeemed on May 26, 1994 at a price of
$21.60 per share plus accrued dividends.
UTILICORP
41
<PAGE>
NOTE 8: INCOME TAXES
Income tax expense consists of the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
--------------------------------------------------------------------------------
<S> <C> <C> <C>
CURRENTLY PAYABLE:
Federal $14.8 $22.6 $ 9.7
Foreign 2.9 4.9 6.3
State (1.5) (2.2) .8
DEFERRED:
Federal
Accelerated depreciation 14.3 27.0 26.6
Alternative minimum tax (20.4) (23.2) (15.0)
Restructuring charge 7.9 (23.7) --
Intangible drilling costs 15.2 10.0 --
Purchased gas adjustment clauses (.6) 1.9 (1.4)
Federal tax rate increase -- 2.7 --
Other 9.8 5.1 2.0
State 8.2 5.7 3.7
INVESTMENT TAX CREDIT AMORTIZATION (1.3) (1.3) (1.1)
--------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $49.3 $29.5 $31.6
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
</TABLE>
In the first quarter of 1993, the company adopted Statement of Financial
Accounting Standards No. 109 (SFAS No. 109), "Accounting for Income Taxes."
SFAS No. 109 requires that deferred tax liabilities be established for income
tax benefits associated with temporary differences including those previously
passed through to ratepayers. Since such deferred tax liabilities will be
collected in rates from customers, a regulatory asset was established. The
company's net SFAS No. 109 regulatory assets were approximately $72 million and
$66 million at December 31, 1994 and 1993, respectively.
In August 1993, passage of the Budget Reconciliation Act of 1993 (the Act)
increased the statutory federal income tax rate from 34% to 35%. This tax rate
change increased income tax expense by approximately $4.0 million, of which $2.7
million represented a non-cash adjustment to increase deferred tax liabilities
as of January 1, 1993.
The company has an alternative minimum tax credit carryforward of
approximately $83.5 million at December 31, 1994. Alternative minimum tax
credits can be carried forward indefinitely and the company has not recorded a
valuation allowance against its tax credit carryforwards. The company also has
a tax net operating loss carryforward of approximately $69 million which expires
beginning in 2008.
The principal components of the company's deferred income taxes consist of
the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993
-------------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX ASSETS:
Alternative minimum tax credit
carryforward $ 83.5 $ 73.8
Net operating loss carryforward 26.3 19.0
Restructuring charges 16.0 25.0
-------------------------------------------------------------------------------
TOTAL DEFERRED TAX ASSETS 125.8 117.8
-------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES:
Accelerated depreciation and
other plant differences
Regulated 176.5 163.1
Non-regulated 168.7 128.4
Regulatory asset--SFAS 109 32.8 25.8
Other, net 27.2 13.4
-------------------------------------------------------------------------------
TOTAL DEFERRED TAX LIABILITIES 405.2 330.7
-------------------------------------------------------------------------------
DEFERRED INCOME TAXES, NET $279.4 $212.9
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
</TABLE>
UTILICORP
42
<PAGE>
The company's effective income tax rates differed from the statutory federal
income tax rates primarily due to the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------------------------------------------
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
STATUTORY FEDERAL INCOME TAX RATE 35.0% 35.0% 34.0%
Tax effect of:
Temporary differences passed through,
primarily removal costs (1.3) (.8) (1.0)
Investment tax credit amortization (.9) (1.1) (1.2)
Gain on sale of subsidiary stock -- (14.4) --
State income taxes, net of federal benefit 3.1 2.4 3.4
Federal tax rate increase -- 2.3 --
Difference in tax rate of foreign subsidiaries .6 .8 1.9
Other (2.2) 1.3 .3
---------------------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 34.3% 25.5% 37.4%
---------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------
</TABLE>
NOTE 9: EMPLOYEE BENEFITS
The following table represents the funded status of the pension plans and
the amounts included in the Consolidated Balance Sheets and Statements of
Income:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation $119.4 $113.5 $83.6
Accumulated benefit obligation 122.6 116.5 86.3
---------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------
Projected benefit obligation $152.1 $144.6 $108.1
Plan assets at fair value (primarily publicly traded
common stocks and bonds)* 161.4 168.3 134.6
---------------------------------------------------------------------------------------------------------------------
Excess of plan assets over the projected benefit obligation 9.3 23.7 26.5
Unrecognized net loss from past experience
different from that assumed 22.0 7.2 2.0
Unrecognized net asset being recognized over 16 years (13.7) (15.6) (16.8)
Unrecognized prior service cost (.7) .1 .6
---------------------------------------------------------------------------------------------------------------------
Pension asset included in prepayments $ 16.9 $ 15.4 $ 12.3
---------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------
Net pension expense included the following components:
Service cost $ 5.6 $ 5.3 $ 4.5
Interest cost on projected benefit obligation 11.0 10.4 8.0
Actual return on plan assets .6 (16.9) (6.6)
Regulatory adjustment .5 .3 --
Net amortization and deferral (16.7) 2.2 (6.2)
---------------------------------------------------------------------------------------------------------------------
Net pension expense (credit) $ 1.0 $ 1.3 $ (.3)
---------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------
Discount rate assumed 7.89% 7.89% 8.21%
Assumed rate of return on future compensation levels 5.0 - 5.5% 5.0 - 5.5% 5.0 - 6.0%
Assumed long-term rate of return on assets 8.5 - 9.0% 8.5 - 9.0% 9.0%
---------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------
<FN>
*INCLUDES $1.1 AND $1.0 MILLION OF THE COMPANY'S CONVERTIBLE PREFERENCE STOCK AT
DECEMBER 31, 1993 AND 1992, RESPECTIVELY. NO CONVERTIBLE PREFERENCE STOCK WAS
HELD AT DECEMBER 31, 1994.
</TABLE>
UTILICORP
43
<PAGE>
The company has pension plans covering substantially all qualified union
and non-union employees. The benefit formulas vary and are based either on
years of service multiplied by a percentage of salary, or a flat benefit based
upon years of service.
The company's policy is to fund, at a minimum, an amount sufficient to meet
all ERISA funding requirements. In certain of its jurisdictions, the company
has recorded pension expense equal to its funding contribution, consistent with
the rate treatment allowed for this cost.
Other Post-Retirement Benefits. The company provides post-retirement
health care and life insurance benefits to certain employees. A majority of
such retirees pay a portion of the cost of these benefits.
Effective January 1, 1993, the company adopted SFAS No. 106, "Employers'
Accounting for Post-Retirement Benefits Other Than Pensions," for its U.S.
operations, which requires accrual of post-retirement benefits during the years
employees provide services. The company has elected to amortize the estimated
unfunded accumulated obligation at January 1, 1994, approximately $43 million,
over 20 years. Expense of approximately $.6 and $.6 million was recognized for
the service cost of benefits accrued and $2.9 and $3.4 million for interest
accrued on the accumulated projected benefit obligation for the years ended
December 31, 1994 and 1993, respectively.
The following table summarizes the status of the company's post-retirement
plans for financial statement purposes and the related amount included in the
Consolidated Balance Sheet at December 31, 1994:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993
---------------------------------------------------------------
<S> <C> <C>
Actuarial present value of post-
retirement benefit obligations:
Retirees $24.1 $29.5
Other fully eligible participants 7.6 9.0
Other active participants 8.3 6.8
Plan assets at fair value (.3) --
Unrecognized transition
obligation (36.4) (41.0)
Unrecognized net gain (loss) 3.3 (1.8)
----------------------------------------------------------------
Accrued liability $ 6.6 $ 2.5
----------------------------------------------------------------
----------------------------------------------------------------
</TABLE>
For measurement purposes, an annual health care cost growth rate of 12.5%
was assumed for 1995, decreasing to 8.25% by 1996 and 6% thereafter. The rate
of change in health care cost has a significant effect on the projected benefit
obligation. Increasing the rate by 1% each year would have increased the
present value of the accumulated projected benefit obligation by $3.0 million
and the aggregate of the service and interest cost components by $.3 million in
1994. The accumulated post-retirement benefit obligation was discounted at a
weighted average rate of 7.75%.
Pursuant to regulatory orders or precedents, certain regulated divisions of
the company have deferred as a regulatory asset the incremental costs associated
with SFAS No. 106. At December 31, 1994, the amount deferred was not
significant.
NOTE 10: COMMITMENT AND CONTINGENCIES
Commitments. The company has various commitments for the years 1995
through 1999 relating primarily to power and gas supply commitments, fixed price
sales obligations and lease and rental commitments. A table of the company's
estimated capital expenditures and more significant estimated commitments
follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
DOLLARS IN MILLIONS 1995 1996 1997 1998 1999
------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Capital expenditures $278.5 $278.7 $294.2 $255.6 $259.8
Future minimum
lease payments 23.6 20.6 18.2 18.9 18.2
Purchased power
obligations 72.6 74.5 74.4 72.4 70.4
Coal contracts 54.3 40.8 41.9 43.3 44.2
Price ranges ------------$15.25 to $27.40 per ton----------
Fixed price sales
obligations (BCF) 20.7 15.2 15.2 15.2 15.2
Price ranges --------------$1.60 to $3.50 per MCF----------
------------------------------------------------------------------------
------------------------------------------------------------------------
</TABLE>
UTILICORP
44
<PAGE>
Future minimum lease payments primarily relate to the Jeffrey Energy Center
(JEC) interest, peaking turbines, coal cars, and office space. Rent expense for
the years 1994, 1993 and 1992 was (in millions) $26.4, $25.7 and $24.7,
respectively.
Purchased power obligations for 1995 through 1999 are estimated to provide
884; 784; 794; 814; and 731 MW, respectively. The largest single contract is
scheduled to provide approximately 6.2% of the company's system requirements
through 1999.
During 1993, the company finalized a joint venture agreement with the
Waikato Electricity Authority in New Zealand for the purchase of an interest in
WEL Energy Group Ltd. (WEL). The company paid $2.7 million at closing and
agreed to pay approximately $17 million over time, as needed for specific
investments, upon call of the WEL Board of Directors. The $17 million was
called in December 1994 and paid in February 1995.
In August 1994, the company entered into a relationship agreement with the
Auckland, New Zealand-based Power New Zealand Limited (PNZ). Under this
relationship, the company has agreed to serve as PNZ's "cornerstone" shareholder
by acquiring 20% of PNZ's shares for approximately $55 million. Under this
relationship, the company has also agreed to acquire PNZ's 18.35% interest in
Wellington, New Zealand-based Energy Direct Corporation Limited for
approximately $21 million. These investments are expected to be completed in
1995.
In September 1994, UtiliCorp expressed interest in acquiring all or some of
the utility distribution properties of Columbia Gas System, Inc. Columbia
operates gas distribution utilities in five states and serves 1.5 million
customers. At this time management does not know if the proposal will be
accepted.
At December 31, 1994, UtilCo Group had unconditional capital commitments to
fund partnership capital in 1995 and 1996 aggregating $11.7 million. In
addition, UtilCo Group has a standby partnership capital commitment of $2.4
million.
The company has agreements with financial institutions to sell, on a
continuing basis, up to $205 million of eligible accounts receivable on a
limited recourse basis. At December 31, 1994, 1993, and 1992, the amounts of
receivables sold under these agreements were $117.6 million, $139.1 million and
$150.0 million, respectively. Fees associated with these sales were
approximately (in millions) $6.9 in 1994, $5.4 in 1993 and $5.7 in 1992.
Environmental. The company is subject to various environmental laws,
including regulations governing air and water quality and the storage and
disposal of hazardous or toxic wastes. The company assesses, on an ongoing
basis, measures that may need to be taken to comply with these laws and
regulations related to hazardous material and hazardous waste compliance and
remediation activities.
The company owns or previously operated 28 former manufactured gas plants
(MGPs) which may, or may not, require some form of environmental remediation.
The company has contacted appropriate federal and state agencies and is in the
process of determining what, if any, specific cleanup activities may be needed
at these sites.
As of December 31, 1994, the company has spent approximately $4.0 million
for investigating and remediating its MGP sites. The company currently
estimates that it will spend a minimum of approximately $8.0 million over the
next several years on the company's identified MGP sites. These amounts could
change materially based upon further investigations, the actions of
environmental agencies and the financial viability of other responsible parties.
Additionally, the ultimate liability may be significantly affected if the
company is held responsible for parties not financially able to contribute to
these costs. Based on prior experience, available facts and existing law, the
company has recorded a liability of $8.0 million representing its estimate of
the amount of environmental costs currently expected to be incurred.
The company has received favorable rate orders for recovery of its
environmental cleanup costs in certain jurisdictions. In other jurisdictions,
favorable regulatory precedent exists for the recovery of these costs. The
company is also pursuing recovery from insurance carriers and other potentially
responsible parties.
It is management's opinion that the ultimate resolution of these
environmental matters will not have a material adverse impact upon the financial
position or results of operations of the company.
UTILICORP
45
<PAGE>
Aquila -- Unusual Loss Provision. In 1992, the company recognized a
$17.7 million pretax charge against earnings ($11.3 million after tax). This
charge related to improper payments by former employees of Aquila Energy
Resources, a wholly-owned subsidiary of Aquila, during the course of
transactions to acquire certain natural gas and oil properties.
In 1994, the company settled with certain defendants in lawsuits filed as a
result of the discovery in 1992 of improper payments. These settlements and
insurance recoveries net of legal and related costs resulted in a favorable
adjustment to income from operations of $2.4 million.
Other. The company is subject to various legal proceedings and claims
which arise in the ordinary course of business operations. In the opinion of
management, the amount of liability, if any, with respect to these actions
would not materially affect the consolidated financial position of the company
or its results of operations.
NOTE 11: FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash and cash equivalents and short-term debt are carried at cost which
approximates fair value. The fair value of long-term debt and redeemable
preference stock is estimated based on quoted market prices for the same or
similar issues or on the current rates offered for instruments of the same
remaining maturities.
The estimated fair value of the company's financial instruments at December
31, 1994, 1993 and 1992 is shown below. Because a substantial portion of the
company's operations are regulated, the company believes that any gains or
losses related to the retirement of debt or redemption of preference stock would
not have a material effect on the company's financial position or results of
operations.
<TABLE>
<CAPTION>
CARRYING AMOUNT FAIR VALUE
---------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992 1994 1993 1992
---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Long-term debt, including maturities $1,115.7 $1,011.5 $896.7 $1,094.4 $1,127.9 $977.9
Redeemable preference stock -- 58.5 60.7 -- 88.7 80.0
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
</TABLE>
The company uses financial instruments to hedge price fluctuations in its
portfolio of commodity transactions. The financial instruments used include
futures and options traded on the New York Mercantile Exchange and swaps and
options traded in the over-the-counter market. The company is subject to credit
risk on its over-the-counter transactions and monitors the creditworthiness of
its counterparties, which consist primarily of large financial institutions.
Margin calls are generally required on financial instruments to address
significant fluctuations in market prices. Margin deposits of $44.8 million and
option premiums paid cover all but $9.9 million of the net future cash
requirements, based on current market conditions.
The estimated market value and cash flow requirements for these financial
instruments are based upon the market prices in effect at the financial
statement date and change with fluctuations in the market price of the related
commodity. These financial instruments are off-balance sheet, and changes in
market values will be recognized as a commodity being hedged is received,
delivered or produced.
At December 31, 1994, the company had natural gas financial instruments
with a contractual volume of 310 BCF expiring through 2007. The market value of
these instruments as of December 31, 1994 was $59.3 million less than contract
value.
The market values above do not reflect the market value of the company's
entire commodity portfolio. In addition to financial instruments, the company
has entered into fixed price commodity transactions and is a producer of gas,
oil and natural gas liquids. The company routinely monitors the aggregate
market value of its existing commodity transactions, gas and oil production, and
financial instruments. Based on the portfolio's aggregate market value at
December 31, 1994, no loss was recorded.
UTILICORP
46
<PAGE>
NOTE 12: SEGMENT INFORMATION
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES:
Electric operations-
Domestic $ 476.1 $ 459.5 $ 426.6
Canadian 80.9 87.4 81.2
------------------------------------------------------------------------------------------------
Total electric operations 557.0 546.9 507.8
Gas operations 618.6 686.1 515.7
Energy related businesses 339.0 338.6 275.4
------------------------------------------------------------------------------------------------
TOTAL REVENUES $1,514.6 $1,571.6 $1,298.9
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION:
Electric operations $ 49.9 $45.9 $41.7
Gas operations 30.1 28.6 24.4
Energy related businesses 59.6 60.8 57.0
Other 7.5 10.7 8.0
------------------------------------------------------------------------------------------------
TOTAL DEPRECIATION, DEPLETION AND AMORTIZATION $147.1 $146.0 $131.1
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM OPERATIONS:
Electric operations-
Domestic $108.6 $101.3 $ 87.6
Canadian 16.7 18.1 21.8
------------------------------------------------------------------------------------------------
Total electric operations 125.3 119.4 109.4
Gas operations 61.8 65.7 41.6
Energy related businesses 43.4 (32.9) 18.0
------------------------------------------------------------------------------------------------
TOTAL INCOME FROM OPERATIONS $230.5 $152.2 $169.0
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS:
Electric operations-
Domestic $ 983.6 $ 927.1 $ 861.5
Canadian 181.0 234.9 193.7
------------------------------------------------------------------------------------------------
Total electric operations 1,164.6 1,162.0 1,055.2
Gas operations 819.9 716.9 579.3
Energy related businesses 717.1 604.2 662.0
Other* 409.5 367.4 256.3
------------------------------------------------------------------------------------------------
TOTAL ASSETS $3,111.1 $2,850.5 2,552.8
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
Capital Expenditures:
Electric operations $ 81.3 $ 87.4 $ 98.1
Gas operations 50.7 53.1 51.7
Energy related businesses 113.6 94.5 48.9
Other* 22.2 28.8 14.8
------------------------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES $267.8 $263.8 $213.5
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
<FN>
* INCLUDES UTILCO GROUP AND OTHER CORPORATE ASSETS.
</TABLE>
UTILICORP
47
<PAGE>
NOTE 13: SUPPLEMENTARY INFORMATION ON GAS AND OIL PRODUCING ACTIVITIES
The following supplementary information is presented in accordance with
Statement of Financial Accounting Standards No. 69 and related SEC accounting
rules. Gas and oil producing activities include the applicable operations of
Aquila and non-regulated operations of a utility division.
<TABLE>
<CAPTION>
Capitalized Costs DECEMBER 31,
-------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
-------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capitalized costs* $427.6 $347.1 $314.8
Less--accumulated depreciation, depletion
and amortization 220.9 179.8 141.0
-------------------------------------------------------------------------------------------
Net Capitalized Costs $206.7 $167.3 $173.8
-------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------
<FN>
* INCLUDES UNPROVEN PROPERTIES OF $12.2 MILLION FOR 1994.
</TABLE>
<TABLE>
<CAPTION>
Costs Incurred YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
-------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Acquisition costs $28.5 $ 2.2 $ 4.9
Development costs 53.3 37.5 16.0
-------------------------------------------------------------------------------------------
Total $81.8 $39.7 $20.9
-------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------
<CAPTION>
Results of Operations YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
-------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Gas $56.7 $58.0 $42.9
Oil 16.6 20.2 29.3
-------------------------------------------------------------------------------------------
Total Revenues 73.3 78.2 72.2
-------------------------------------------------------------------------------------------
Expenses:
Production costs 17.5 18.9 19.7
Depreciation, depletion and amortization 41.1 39.6 39.7
Unusual item--loss provision -- -- 10.7
-------------------------------------------------------------------------------------------
Total Expenses 58.6 58.5 70.1
-------------------------------------------------------------------------------------------
Results before income taxes 14.7 19.7 2.1
Income Taxes 5.1 6.9 .8
-------------------------------------------------------------------------------------------
Results of Operations $ 9.6 $12.8 $ 1.3
-------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------
</TABLE>
Reserve Quantity Information (Unaudited). The following reserve quantity
estimates (all located in the United States) as well as information regarding
future production and cash flows were based primarily on reserve studies
prepared by Netherlands, Sewell and Associates, Inc. Such estimates are
inherently imprecise and may be subject to revision.
UTILICORP
48
<PAGE>
<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL AND CONDENSATE
(BILLION CUBIC FEET) (THOUSAND BARRELS)
----------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 1993 1992 1994 1993 1992
----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proven developed and undeveloped reserves:
Beginning of year 110.9 142.5 208.8 3,544 5,851 8,016
Purchases of reserves in place 17.4 1.8 1.7 3,096 6 771
Revision of previous estimates 12.7 (17.8) (43.2) 353 (1,325) (1,539)
Production (23.3) (24.4) (25.0) (1,050) (1,133) (1,489)
Extensions 17.6 8.8 .2 447 145 92
----------------------------------------------------------------------------------------------------------
End of Year 135.3 110.9 142.5 6,390 3,544 5,851
----------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------
Proven developed reserves:
Beginning of year 73.3 97.4 168.6 3,058 4,050 6,337
End of year 108.7 73.3 97.4 5,693 3,058 4,050
----------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein (Unaudited). Future pretax net cash flows have been estimated by
applying prices and costs in effect at the end of the years indicated, except
where contractual arrangements exist, to the estimated future production of
proven reserves. Aquila has assigned approximately 60% of the company's future
gas production through 2008 to certain of its long-term fixed price contracts
through a contractual swap arrangement at prices averaging $4.21 per MCF.
Future income tax expenses were computed by applying statutory tax rates
adjusted for permanent differences and tax credits to estimated net future
pretax cash flows.
<TABLE>
<CAPTION>
Standardized Measure DECEMBER 31,
--------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future cash inflows $549.9 $418.7 $513.7
Future production costs (152.9) (112.5) (122.8)
Future development costs (38.6) (38.0) (49.4)
Future income tax expenses (88.1) (44.3) (76.0)
--------------------------------------------------------------------------------------------------
Future net cash flows 270.3 223.9 265.5
10% annual discount (98.0) (75.6) (88.8)
--------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $172.3 $148.3 $176.7
--------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------
<CAPTION>
Changes in Standardized Measure YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Sales and transfers of gas and oil produced, net of
production costs $ (55.8) $ (59.3) $ (52.5)
Net changes in prices and production costs related to
future production (9.6) (1.0) 80.3
Development costs incurred during the period 21.3 27.1 14.7
Extensions 38.0 15.5 1.5
Changes in estimated future development costs (9.0) (5.8) (34.4)
Revisions of previous quantity estimates 22.8 (32.7) (73.9)
Purchases of reserves in place 39.4 2.5 8.6
Accretion of discount 17.6 22.6 26.9
Net change in income taxes (25.7) 20.6 (.6)
Changes in production rates and other (15.0) (17.9) (12.1)
--------------------------------------------------------------------------------------------------
Net increase (decrease) in discounted future net cash flows 24.0 (28.4) (41.5)
--------------------------------------------------------------------------------------------------
Beginning of year 148.3 176.7 218.2
End of year $172.3 $148.3 $176.7
--------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------
</TABLE>
UTILICORP
49
<PAGE>
NOTE 14: QUARTERLY FINANCIAL DATA (UNAUDITED)
Due to the timing of acquisitions, the effect of weather on sales, and other
factors characteristic of utility operations and energy related businesses,
financial results for interim periods are not necessarily indicative of trends
for any 12-month period.
<TABLE>
<CAPTION>
1994 QUARTERS 1993 QUARTERS
------------------------------------------------------------------------------------------------------------------------
IN MILLIONS EXCEPT PER SHARE First Second Third Fourth First Second Third Fourth (A)
------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $497.3 $311.6 $315.1 $390.6 $480.9 $329.4 $330.1 $431.2
Income (loss) from operations 83.6 34.7 48.4 63.8 78.6 34.6 49.0 (10.0)
Net income 39.0 7.4 14.5 33.6 34.8 7.3 11.0 33.3
------------------------------------------------------------------------------------------------------------------------
Earnings per common share:
Primary (B) $.88 $.15 $.31 $.76 $.87 $.13 $.22 $.76
Fully diluted (C) .85 .15 .31 .74 .83 .13 .22 .72
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Cash dividend per common share $.42 $.42 $.43 $.43 $.40 $.40 $.40 $.42
Market price per common share:
High $31.63 $31.38 $29.75 $27.75 $28.63 $29.63 $34.00 $33.50
Low 29.00 28.00 26.25 25.38 27.13 27.75 28.88 30.13
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
<FN>
(A) SEE NOTE 2 FOR DISCUSSION OF RESTRUCTURING CHARGE AND GAIN ON SALE OF
SUBSIDIARY STOCK.
(B) THE SUM OF THE QUARTERLY PRIMARY EARNINGS PER SHARE AMOUNTS DIFFERS FROM
THAT REFLECTED IN THE CONSOLIDATED STATEMENTS OF INCOME DUE TO THE WEIGHTING
OF COMMON SHARES OUTSTANDING DURING EACH OF THE RESPECTIVE PERIODS.
(C) THE SUM OF THE QUARTERLY FULLY DILUTED EARNINGS PER SHARE AMOUNTS DIFFERS
FROM THAT REFLECTED IN THE CONSOLIDATED STATEMENTS OF INCOME BECAUSE THE
COMPANY'S CONVERTIBLE SECURITIES WERE ANTI-DILUTIVE IN CERTAIN QUARTERLY
CALCULATIONS.
</TABLE>
UTILICORP
50
<PAGE>
REPORT OF MANAGEMENT
The management of UtiliCorp United Inc. is responsible for the information that
appears in this annual report, including its accuracy. The accompanying
consolidated financial statements were prepared in accordance with generally
accepted accounting principles. In addition to selecting appropriate accounting
principles, management is responsible for the manner of presentation and for the
reliability of the information. In fulfilling this responsibility, it is
necessary for management to make estimates based on currently available
information and judgments of current conditions and circumstances.
Through well-developed systems of internal control, management seeks to
assure the integrity and objectivity of the consolidated financial information
contained herein. These systems of internal control are designed to provide
reasonable assurance that the assets of the company are safeguarded and that the
transactions are executed to management's authorizations, and are recorded in
accordance with the appropriate accounting principles.
The Board of Directors participates in the financial information reporting
process through its Audit Committee, which selects the independent accountants
and reviews, along with management, the company's financial reporting and
internal accounting controls, policies, and practices.
/s/ Richard Green Jr.
Richard C. Green, Jr.
Chairman of the Board, President
and Chief Executive Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF UTILICORP UNITED INC.:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of UtiliCorp United Inc. and subsidiaries at December 31, 1994,
1993 and 1992 and the related consolidated statements of income, common
shareholders' equity, and cash flows for the three years then ended. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits 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 consolidated financial position of UtiliCorp
United Inc. and subsidiaries at December 31, 1994, 1993 and 1992, and the
consolidated results of their operations and their cash flows for the years then
ended in conformity with generally accepted accounting principles.
As explained in Notes 8 and 9 to the consolidated financial statements,
effective January 1, 1993 the company changed its methods of accounting for
income taxes and post-retirement benefits other than pensions.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Kansas City, Missouri
January 31, 1995
UTILICORP
51
<PAGE>
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS EXCEPT PER SHARE 1994 1993 1992 1991
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues:
Electric operations $ 557.0 $ 546.9 $ 507.8 $ 379.4
Gas operations 618.6 686.1 515.7 496.0
Energy related businesses 339.0 338.6 275.4 199.8
--------------------------------------------------------------------------------------------------------------
Total revenues 1,514.6 1,571.6 1,298.9 1,075.2
Total expenses 1,284.1 1,419.4 1,129.9 879.2
--------------------------------------------------------------------------------------------------------------
Income from operations (a) 230.5 152.2 169.0 196.0
Total interest charges, minority interests
and other 86.8 36.3 84.5 74.8
--------------------------------------------------------------------------------------------------------------
Income before income taxes 143.7 115.9 84.5 121.2
Income taxes 49.3 29.5 31.6 43.6
--------------------------------------------------------------------------------------------------------------
Net income (b) 94.4 86.4 52.9 77.6
Preference and preferred dividends 3.0 6.9 6.9 7.8
--------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON SHARES $ 91.4 $ 79.5 $ 46.0 $ 69.8
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Primary earnings per common share (b) $2.08 $1.95 $1.32 $2.37
Return on average common equity (b) 10.24% 9.84% 6.93% 13.32%
Cash dividends paid per common share $ 1.70 $ 1.62 $ 1.60 $ 1.54
Book value per common share 20.24 20.27 18.66 19.18
Market price of common stock at year end 26.50 31.75 27.63 28.50
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Electric $1,164.6 $1,162.0 $1,055.2 $1,026.0
Gas 819.9 716.9 579.3 530.1
Energy related 717.1 604.2 662.0 643.1
Other 409.5 367.4 256.3 188.1
--------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $3,111.1 $2,850.5 $2,552.8 $2,387.3
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Utility construction expenditures $ 132.0 $ 140.5 $ 149.8 $134.0
Non-regulated investment expenditures (c) 135.8 123.3 63.7 169.8
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Common shareholders' equity $ 906.8 $ 851.7 $ 661.1 $ 660.7
Preference and preferred stock 25.4 83.9 95.1 97.1
Long-term debt (d) 1,115.7 1,011.5 896.7 931.6
Short-term debt (e) 182.4 70.0 230.9 111.0
--------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND SHORT-TERM DEBT (d) $2,230.3 $2,017.1 $1,883.8 $1,800.4
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
Capitalization Ratios
Common shareholders' equity 40.7% 42.2% 35.1% 36.7%
Preference and preferred stock 1.1 4.2 5.0 5.4
Long-term debt (d) 50.0 50.1 47.6 51.7
Short-term debt (e) 8.2 3.5 12.3 6.2
--------------------------------------------------------------------------------------------------------------
TOTAL 100.0% 100.0% 100.0% 100.0%
--------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------
UTILICORP
52
<PAGE>
-------------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS EXCEPT PER SHARE 1990 1989 1988 1987 1986 1985 1984
-------------------------------------------------------------------------------------------------------------------------------
REVENUES:
Electric operations $ 303.7 $ 285.9 $ 275.8 $ 227.2 $ 192.6 $ 185.8 $ 178.2
Gas operations 503.9 446.1 397.0 367.7 403.2 57.4 56.1
Energy related businesses 75.9 40.4 13.1 4.5 2.4 -- --
-------------------------------------------------------------------------------------------------------------------------------
Total revenues 883.5 772.4 685.9 599.4 598.2 243.2 234.3
Total expenses 748.9 658.3 587.7 517.0 530.2 180.3 173.1
-------------------------------------------------------------------------------------------------------------------------------
Income from operations (a) 134.6 114.1 98.2 82.4 68.0 62.9 61.2
Total interest charges, minority interest
and other 59.5 49.0 38.2 29.8 28.6 13.3 14.0
-------------------------------------------------------------------------------------------------------------------------------
Income before income taxes 75.1 65.1 60.0 52.6 39.4 49.6 47.2
Income taxes 24.7 21.0 20.0 19.4 9.7 22.7 21.4
-------------------------------------------------------------------------------------------------------------------------------
Net Income (b) 50.4 44.1 40.0 30.5 29.7 26.9 25.8
Preference and preferred dividends 7.9 5.7 2.5 3.1 4.0 4.4 4.3
-------------------------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON SHARES $ 42.5 $ 38.4 $ 37.5 $ 27.4 $ 25.7 $ 22.5 $ 21.5
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
Primary earnings per common share (b) $ 1.77 $ 1.84 $ 1.93 $ 1.64 $ 1.69 $ 1.80 $ 1.74
Return on average common equity (b) 10.69% 11.62% 12.85% 11.85% 13.40% 16.24% 17.54%
Cash dividends paid per common share $ 1.46 $ 1.42 $ 1.04 $ .93 $ .87 $ .77 $ .64
Book value per common share $ 17.00 16.36 15.49 14.20 13.31 11.79 10.56
Market price of common stock at year end 20.38 22.00 18.88 14.14 19.28 13.10 11.05
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
Electric $ 759.6 $ 700.6 $ 642.1 $ 594.2 $ 420.3 $ 408.8 $ 390.3
Gas 509.3 464.7 283.2 275.2 285.2 297.7 34.9
Energy related 377.4 179.4 88.6 31.4 33.4 -- --
Other 176.9 114.1 109.6 65.3 26.8 24.3 6.3
-------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $1,823.2 $1,458.8 $1,123.5 $ 966.1 $ 765.7 $ 730.8 $ 431.5
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
Utility construction expenditures $ 118.9 $ 98.3 $ 78.7 $ 56.7 $ 47.0 $ 31.7 $ 24.2
Non-regulated investment expenditures (c) 244.5 78.7 73.2 21.4 12.9 -- --
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
Common shareholders' equity $ 477.5 $ 372.3 $ 321.1 $ 264.4 $ 211.7 $ 165.7 $ 131.1
Preference and preferred stock 97.2 97.4 95.1 25.0 33.0 41.8 42.8
Long-term debt (d) 679.3 442.6 386.0 320.1 283.6 234.9 140.0
Short-term debt (e) 48.7 86.2 53.0 69.9 32.0 138.3 14.0
-------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND SHORT-TERM DEBT (d) $1,302.7 $ 998.5 $ 795.2 $ 679.4 $ 560.3 $ 580.7 $ 327.9
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
Capitalization Ratios
Common shareholders' equity 36.7% 37.3% 40.4% 38.9% 37.8% 28.5% 40.0%
Preference and preferred stock 7.5 9.8 4.4 3.7 5.9 7.2 13.0
Long-term debt (d) 52.1 44.3 48.5 47.1 50.6 40.5 42.7
Short-term debt (e) 3.7 8.6 6.7 10.3 5.7 23.8 4.3
-------------------------------------------------------------------------------------------------------------------------------
TOTAL 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
-------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------------
<FN>
(a) AFTER RESTRUCTURING CHARGE OF $69.8 MILLION IN 1993 AND UNUSUAL LOSS
PROVISION OF $17.7 MILLION IN 1992.
(b) INCLUDES CUMULATIVE EFFECT ON PRIOR YEARS OF ACCOUNTING CHANGES OF ($2.7),
OR ($.16) PER SHARE, IN 1987.
(c) INVESTMENTS IN NON-REGULATED GENERATING ASSETS AND ENERGY RELATED PROPERTIES.
(d) INCLUDES CURRENT MATURITIES.
(e) DOES NOT REPRESENT PERMANENT CAPITAL. WILL BE FINANCED WITH DEBT AND EQUITY
SECURITIES CONSIDERING FINANCIAL MARKET CONDITIONS
</TABLE>
UTILICORP
53
<PAGE>
ELECTRIC AND GAS STATISTICS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1994 1993 1992 1991
-------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues:
Residential $245.8 44.1% $236.8 $212.5 $173.6
Commercial 157.3 28.2 156.2 148.3 102.0
Industrial 75.1 13.5 76.0 73.3 46.4
Other 78.8 14.2 77.9 73.7 57.4
-------------------------------------------------------------------------------
TOTAL REVENUES $557.0 100.0% $546.9 $507.8 $379.4
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
MWH sales(000'S):
Residential 3,512 34.7% 3,536 3,176 2,735
Commercial 2,611 25.8 2,528 2,367 1,672
Industrial 1,897 18.7 1,921 1,800 1,197
Other 2,099 20.8 1,939 1,748 1,468
-------------------------------------------------------------------------------
TOTAL SALES 10,119 100.0% 9,924 9,091 7,072
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Communities served 373 369 364 364
-------------------------------------------------------------------------------
Customers at year end:
Residential 367,943 86.3% 360,429 354,086 346,434
Commercial 54,444 12.8 53,475 52,748 51,765
Industrial 321 -- 302 301 302
Other 3,706 .9 3,678 3,691 3,634
-------------------------------------------------------------------------------
TOTAL CUSTOMERS 426,414 100.0% 417,884 410,826 402,135
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Generation mix:
Coal 69.9 69.3% 71.1% 67.9%
Natural gas and oil 8.9 7.1 3.5 2.7
Hydro 21.2 23.6 25.4 29.4
-------------------------------------------------------------------------------
TOTAL 100.0% 100.0% 100.0% 100.0%
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Generating capability (MW):
Coal 868 48.8% 864 863 858
Natural gas and oil 705 39.7 700 716 723
Hydro 205 11.5 205 206 206
-------------------------------------------------------------------------------
Total generating capability 1,778 100.0% 1,769 1,785 1,787
Firm purchased power 904 840 820 694
-------------------------------------------------------------------------------
TOTAL SYSTEM CAPABILITY 2,682 2,609 2,605 2,481
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Revenues:
Residential $356.4 57.6% $380.2 $276.0 $257.6
Commercial 156.9 25.4 177.5 130.0 118.8
Industrial 66.7 10.8 89.8 76.4 90.9
Other 38.6 6.2 38.6 33.3 28.7
-------------------------------------------------------------------------------
TOTAL REVENUES $618.6 100.0% $686.1 $515.7 $496.0
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
MCF sales(000'S):
Residential 71,208 55.6% 74,421 58,095 56,383
Commercial 35,952 28.1 40,232 32,239 30,861
Industrial 18,439 14.4 26,868 23,841 30,908
Other 2,420 1.9 3,672 2,683 1,928
-------------------------------------------------------------------------------
TOTAL SALES 128,019 100.0% 145,193 116,858 120,080
Gas transportation 135,924 115,877 112,831 108,044
-------------------------------------------------------------------------------
TOTAL SALES AND
TRANSPORTATION 263,943 261,070 229,689 228,124
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Communities served 792 774 708 666
-------------------------------------------------------------------------------
Customers at year end:
Residential 698,156 89.5% 661,930 535,058 519,149
Commercial 76,015 9.8 73,365 60,054 58,299
Industrial 3,878 .5 3,874 3,622 3,666
Other 1,581 .2 1,185 582 539
-------------------------------------------------------------------------------
TOTAL CUSTOMERS 779,630 100.0% 740,354 599,316 581,653
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
UTILICORP
54
<PAGE>
ELECTRIC AND GAS STATISTICS
------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS 1990 1989 1988 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------------------------
Revenues:
Residential $143.6 $131.0 $129.2 $111.0 $ 92.0 $ 87.2 $ 85.4
Commercial 79.2 75.7 71.7 60.3 51.0 49.3 46.8
Industrial 36.1 35.1 34.5 28.5 27.1 26.7 24.4
Other 44.8 44.1 40.4 27.4 22.5 22.6 21.6
------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES $303.7 $285.9 $275.8 $227.2 $192.6 $185.8 $178.2
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
MWH sales (000'S):
Residential 2,379 2,300 2,232 1,565 1,140 1,044 1,042
Commercial 1,367 1,333 1,279 1,034 743 699 671
Industrial 1,022 1,027 1,014 708 572 547 502
Other 1,308 1,189 1,211 666 412 412 431
------------------------------------------------------------------------------------------------------------------------
TOTAL SALES 6,076 5,849 5,736 3,973 2,867 2,702 2,646
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Communities served 209 209 209 209 122 122 122
------------------------------------------------------------------------------------------------------------------------
Customers at year end:
Residential 226,223 221,482 215,360 211,169 131,048 126,880 123,402
Commercial 27,866 27,536 26,690 25,778 15,882 15,364 14,897
Industrial 180 174 176 172 143 139 145
Other 3,021 2,976 3,850 2,902 2,389 2,293 2,269
------------------------------------------------------------------------------------------------------------------------
TOTAL CUSTOMERS 257,290 252,168 246,076 240,021 149,462 144,676 140,713
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Generation mix:
Coal 66.4% 63.2% 64.9% 85.4% 99.6% 99.9% 99.6%
Natural gas and oil .4 .5 .5 .5 .4 .1 .4
Hydro 33.2 36.3 34.6 14.1 -- -- --
------------------------------------------------------------------------------------------------------------------------
TOTAL 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Generating capability (MW):
Coal 652 652 629 622 622 620 616
Natural gas and oil 295 295 295 295 295 296 296
Hydro 206 206 206 206 -- -- --
------------------------------------------------------------------------------------------------------------------------
Total generating capability 1,153 1,153 1,130 1,123 917 916 912
Firm purchased power 520 444 374 299 -- -- --
------------------------------------------------------------------------------------------------------------------------
TOTAL SYSTEM CAPABILITY 1,673 1,597 1,504 1,422 917 916 912
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Revenues:
Residential $261.1 $223.0 $188.8 $162.0 $166.9 $28.5 $29.3
Commercial 121.8 110.5 95.8 80.8 87.5 13.2 12.4
Industrial 90.5 93.1 96.2 115.1 144.2 12.6 11.5
Other 30.5 19.5 16.2 9.8 4.6 3.1 2.9
------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES $503.9 $446.1 $397.0 $367.7 $403.2 $57.4 $56.1
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
MCF sales (000'S):
Residential 53,297 48,128 39,517 35,223 34,083 6,070 5,942
Commercial 29,950 28,373 24,121 21,323 21,423 3,184 2,685
Industrial 28,320 32,219 35,386 46,371 46,115 3,588 2,948
Other 1,875 1,563 1,623 1,394 1,420 625 593
------------------------------------------------------------------------------------------------------------------------
TOTAL SALES 113,424 110,283 100,647 104,311 103,041 13,467 12,168
Gas Transportation 105,222 84,783 66,138 35,836 13,800 -- --
------------------------------------------------------------------------------------------------------------------------
TOTAL SALES AND
TRANSPORTATION 218,646 195,066 166,785 140,147 116,841 13,467 12,168
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Communities served 637 503 361 360 359 313 27
------------------------------------------------------------------------------------------------------------------------
Customers at year end:
Residential 509,249 476,296 360,413 346,516 338,006 317,073 53,659
Commercial 57,360 54,438 43,217 42,538 42,481 38,872 5,401
Industrial 3,636 3,621 3,159 3,082 3,234 3,260 120
Other 569 512 387 390 378 390 359
------------------------------------------------------------------------------------------------------------------------
TOTAL CUSTOMERS 570,814 534,867 407,176 392,526 384,099 359,595 59,539
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
</TABLE>
UTILICORP
55
<PAGE>
CORPORATE INFORMATION
ANNUAL MEETING
The 1995 annual meeting of shareholders will be held at 10:00 a.m. on
Wednesday, May 3 in Bartle Hall's Grand Hall, Kansas City Convention Center, 301
West 13th Street, Kansas City, Missouri. Parking will be provided in the
Auditorium Plaza garage. A videotape will be available for shareholders unable
to attend.
STOCK LISTINGS
The common and preference shares of UtiliCorp United Inc. are listed on the New
York Stock Exchange. The common shares are also listed on the Pacific and
Toronto stock exchanges. The company's trading symbol is UCU.
At the end of 1994, UtiliCorp had approximately 85,000 common shareholders
with 44.8 million outstanding shares. There was also a total of about 1.0
million shares held in one series of preference stock.
The common shares of Aquila Gas Pipeline Corporation are traded on the New
York Stock Exchange under the symbol AQP. Approximately 18 percent of Aquila
Gas Pipeline is held by the public. UtiliCorp's wholly-owned Aquila Energy
subsidiary holds the remaining 82 percent.
REINVESTMENT AND DIRECT PURCHASE
In February 1995 UtiliCorp introduced an expanded Dividend Reinvestment and
Common Stock Purchase Plan. It combines the dividend reinvestment and optional
cash purchase features of the prior plan with a new direct purchase provision
through which investors can acquire their first shares of UtiliCorp common stock
directly from the company without brokerage fees.
For first-time buyers of UtiliCorp stock, the plan requires a minimum
initial purchase of $250. Additional purchases through the plan may be made on
a monthly basis with a minimum contribution of $50 and a maximum of $10,000 per
month.
Direct shareholders can instruct the company to automatically buy more
shares with all or some of their dividend proceeds. Reinvestment shares are
purchased under the plan at 5% less than the market price, as defined in the
plan prospectus, with no brokerage commissions. Reinvestment participants may
also make cash purchases of shares ranging from $50 up to $10,000 per month, at
market price without commission.
All participants in the company's prior dividend reinvestment plan were
automatically enrolled in the new plan and may take advantage of its added
features. These include provisions for partial reinvestment of dividends,
electronic payment for cash purchases, and safekeeping of share certificates.
SHAREHOLDER INQUIRIES
Questions about your account, including dividend payments, the Dividend
Reinvestment and Common Stock Purchase Plan, direct deposit service or the
transfer of shares, are handled by utility specialists at the company's transfer
agent, First Chicago Trust Company of New York. They can be reached at a toll-
free number for UtiliCorp shareholders: (800) UTILICO, or 884-5426.
Your calls also are always welcome at UtiliCorp. You may contact
Shareholder Relations toll-free at (800) 487-6661, or at (816) 421-6600.
However, calls regarding the transfer of shares, dividend reinvestment, cash
purchases or direct deposit service are normally referred to the transfer agent.
Address mail inquiries to Shareholder Relations, UtiliCorp United, P.O. Box
13287, Kansas City, MO 64199-3287. Mail regarding the transfer of shares should
be addressed to the following:
Transfer Agent. First Chicago Trust Company of New York, Stock Transfer
Department, P.O. Box 2506, Jersey City, NJ 07303-2506. Documents may also be
delivered to 14 Wall Street, Suite 4680, New York, NY 10005.
Co-Transfer Agent. UMB Bank, N.A., 928 Grand, 13th Floor, P.O. Box 410064,
Kansas City, MO 64141; (816) 860-7786.
ADDITIONAL PUBLICATIONS
The following financial publications are available upon request:
Form 10-K. The company's 1994 Annual Report to the Securities and Exchange
Commission.
Corporate Profile. A fact book for the investment community containing
division and subsidiary operating data, a profile of management, historical and
projected financial data, and regulatory information.
UTILICORP
56
<PAGE>
Appendix to Annual Report
- The "graphic" on page 2 is an illustration of a partially folded map of the
United States.
- The photograph on page 3 is a picture of Richard C. Green, Jr. Chairman of
the Board, President and Chief Executive Officer.
- The "graphic" on page 8 is an illustration depicting the introduction of a
new unified brand name.
- The "graphic" on page 12 is an illustration showing the company's new
business groups.
- The "graphic" on page 15 is an illustration of a residential neighborhood
and the inside of a vehicle.
- The "graphic" on page 16 is a chart showing the relative performance of the
company's common stock during the course of the year in terms of market
value verses the S&P Utilities, the S&P 500 and the DJ Utilities. The
twelve month performance data shows the company's common stock down 16.5%
for the year, the S&P Utilities down 13.0%, the S&P 500 down 1.5% and the
DJ Utilities down 20.8%.
- The first "graphic" on page 18 is a map of the company's regulated service
territory. The company's electric-only service territory includes portions
of southeast British Columbia; south-central Colorado; central Kansas;
north-central and western Missouri; and southeast West Virginia. The
company's gas-only service territory includes portions of central and
eastern Colorado; northwest, southeast and northeast Kansas; eastern
Nebraska; northern and southern Minnesota; Iowa; central Missouri; southern
and southern and southwest Michigan; and central West Virginia. The
company's service territory for combination of gas and electric service
includes portions of central Colorado; southern Kansas; and central and
western Missouri.
- The second "graphic" on page 18 is a map of locations of the company's non-
regulated operations. The company's Aquila Energy subsidiary markets
natural gas throughout all of the 48 states in the contiguous United States
with the exception of Oregon, Idaho and Vermont. It also markets gas in
Ontario, Canada and parts of Mexico. Aquila has onshore natural gas and
oil production in portion of northwest and central Oklahoma; western and
central Texas; and south-central Louisiana. Aquila has offshore natural
gas and oil production in the Gulf of Mexico off Texas and Louisiana.
Aquila has pipelines in central Oklahoma; western, southern and eastern
Texas; and in the Gulf of Mexico. Aquila also has two significant gas
processing plants, one in Oklahoma and one southern Texas. The company's
UtilCo Group subsidiary has an ownership interests in independent power
projects in six states.
- The third "graphic" on page 18 is a map of the company's WEL Energy Group
Ltd. service territory in New Zealand.
- The fourth "graphic" on page 18 is a map of the company's UtiliCorp U.K.,
Inc. marketing area in the United Kingdom.
- The fifth "graphic" on page 18 is a map of the UtilCo Groups independent
power project in Jamaica.
- The "graphic" on page 24 is an illustration is the services the company
provides its customers.
- the "graphic" on page 31 is an illustration depicting the "information
superhighway".
<PAGE>
Exhibit 21
UtiliCorp United Inc.
Subsidiaries
1994 Annual Report on Form 10-K
Jurisdiction of
Subsidiary Incorporation
---------- ----------------
West Kootenay Power Ltd. Province of British Columbia
UtilCo Group Inc. Delaware
Aquila Energy Corporation Delaware
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1634
<OTHER-PROPERTY-AND-INVEST> 781
<TOTAL-CURRENT-ASSETS> 514
<TOTAL-DEFERRED-CHARGES> 182
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3111
<COMMON> 45
<CAPITAL-SURPLUS-PAID-IN> 774
<RETAINED-EARNINGS> 107
<TOTAL-COMMON-STOCKHOLDERS-EQ> 907
0
25
<LONG-TERM-DEBT-NET> 977
<SHORT-TERM-NOTES> 182
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 139
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 881
<TOT-CAPITALIZATION-AND-LIAB> 3111
<GROSS-OPERATING-REVENUE> 1515
<INCOME-TAX-EXPENSE> 49
<OTHER-OPERATING-EXPENSES> 283
<TOTAL-OPERATING-EXPENSES> 1284
<OPERATING-INCOME-LOSS> 231
<OTHER-INCOME-NET> 18
<INCOME-BEFORE-INTEREST-EXPEN> 246
<TOTAL-INTEREST-EXPENSE> 102
<NET-INCOME> 94
3
<EARNINGS-AVAILABLE-FOR-COMM> 91
<COMMON-STOCK-DIVIDENDS> 75
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 204
<EPS-PRIMARY> 2.08
<EPS-DILUTED> 2.06
</TABLE>
<PAGE>
Exhibit 99(a)
<TABLE>
<CAPTION>
1994 UTILITY DATA - ELECTRIC OPERATIONS YEAR ENDED DECEMBER 31, 1994
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
MISSOURI PUBLIC SERVICE WEST KOOTENAY POWER
-------------------------------------------------------- ----------------------------------------------------------------------
Generating capability (MW): Generating capability (MW) - Hydro 205
Coal-fired 658 Firm purchased power (MW):*
Gas and oil-fired 286 B.C. Hydro (through 9/2013) 160
Firm purchased power(MW):* Cominco (through 9/2005) 48
Associated Electric (through 5/2001) 180 Cominco (through 12/99) 120
Union Electric (through 5/2001) 135 Washington Water Power (12/94) 50
-------------------------------------------------------- ----------------------------------------------------------------------
TOTAL SYSTEM CAPABILITY 1,259 TOTAL SYSTEM CAPABILITY 583
-------------------------------------------------------- ----------------------------------------------------------------------
-------------------------------------------------------- ----------------------------------------------------------------------
Peak load (MW) 640
Peak load (MW) 960 Load factor 54.0%
Load factor 48.5% HEATING DEGREE-DAYS 3,144
Cooling degree-days 1,351 ----------------------------------------------------------------------
-------------------------------------------------------- ----------------------------------------------------------------------
-------------------------------------------------------- Source of energy (MWH-000's):
Source of energy (MWH-000's): Hydro 1,519
Coal 3,700 Purchased power 1,420
Gas and oil 32 ----------------------------------------------------------------------
Purchased power 516 TOTAL 2,939
-------------------------------------------------------- ----------------------------------------------------------------------
TOTAL 4,248 Average cost of energy (cents/KWH):
-------------------------------------------------------- Generated 1.14
Average cost of energy (cents/KWH): Purchased (including capacity) 1.70
Generated 1.19 ----------------------------------------------------------------------
Purchased (including capacity) 4.74 TOTAL AVERAGE COST OF ENERGY 1.24
-------------------------------------------------------- ----------------------------------------------------------------------
TOTAL AVERAGE COST OF ENERGY 1.62 ----------------------------------------------------------------------
-------------------------------------------------------- WEST VIRGINIA POWER
-------------------------------------------------------- ----------------------------------------------------------------------
WESTPLAINS ENERGY Firm purchased power (MW):*
-------------------------------------------------------- Appalachian Power (through 9/97) 48.3
Generating capability (MW): Peak load (MW) 97
Coal-fired 210 Load factor 46.8%
Gas and oil-fired 419 Heating degree-days 5,093
Firm purchased power (MW):* ----------------------------------------------------------------------
Public Service Company of Colorado ----------------------------------------------------------------------
(through 7/2017) 100 Source of Energy (MWH-000's)
Purchased power 402
Public Service Company of Colorado Average cost of energy purchased
(through 6/2002) 63 (including capacity) (cents/KWH) 3.48
-------------------------------------------------------- ----------------------------------------------------------------------
TOTALY SYSTEM CAPABILITY 792 ----------------------------------------------------------------------
--------------------------------------------------------
-------------------------------------------------------- ELECTRIC TARIFF SALES VOLUMES
Peak load (MW): ----------------------------------------------------------------------
Kansas 418 Residential Commercial Industrial Other
Colorado 229 ----------------------------------------------------------------------
Load factor: Missouri Public Service 40% 28% 15% 17%
Kansas 52.1% WestPlains Energy 26 30 27 17
Colorado 67.1% West Kootenay Power 35 17 14 34
Cooling degree-days: West Virginia Power 54 32 9 5
Kansas 926 ----------------------------------------------------------------------
Colorado 1,247 ----------------------------------------------------------------------
--------------------------------------------------------
-------------------------------------------------------- <FN>
Source of energy (MWH-000's): *Purchased power contract commitments in future years may vary from
Coal 1,318 the December 31, 1994 amount.
Gas and oil 609
Purchased power 1,714
--------------------------------------------------------
TOTAL 3,641
--------------------------------------------------------
Average cost of energy (cents/KWH):
Generated 1.71
Purchased (including capacity) 2.80
--------------------------------------------------------
TOTAL AVERAGE COST OF ENERGY 2.22
--------------------------------------------------------
--------------------------------------------------------
</TABLE>
<PAGE>
Exhibit 99(b)
<TABLE>
<CAPTION>
1994 UTILITY DATA - GAS OPERATIONS YEAR ENDED DECEMBER 31, 1994
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <S> <C>
MISSOURI PUBLIC SERVICE NORTHERN MINNESOTA UTILITIES
-------------------------------------------------------- ---------------------------------------------------------------------
Average cost of purchased gas ($/MCF) $3.28 Average cost of purchased gas ($/MCF) $3.15
------------------------------------------------------- ---------------------------------------------------------------------
Supply mix: Supply mix:
Contract 31% Contract 94%
Spot 69% Spot 6%
------------------------------------------------------- ---------------------------------------------------------------------
Major supplier: Major suppliers:
Aquila Energy Centra Gas Pipelines
Panhandle Trading Co. Northern Natural Gas
Union Pacific Viking Gas Transmission
-------------------------------------------------------- Western Natural Gas
Peak day sendout (MCF) 47,948 ---------------------------------------------------------------------
Heating degree-days 4,825 Peak day sendout 82,745
-------------------------------------------------------- Heating degree-days 9,297
Gas storage capacity (BCF): ---------------------------------------------------------------------
Leased 1.8 Gas storage capacity (BCF)
------------------------------------------------------- Leased .9
------------------------------------------------------- ---------------------------------------------------------------------
PEOPLES NATURAL GAS ---------------------------------------------------------------------
------------------------------------------------------- KANSAS PUBLIC SERVICE
Average cost of purchased gas ($/MCF) $2.85 ---------------------------------------------------------------------
------------------------------------------------------- Average cost of purchased gas ($/MCF) $2.88
Supply mix: ---------------------------------------------------------------------
Contract 35% Supply mix:
Spot 65% Contract 38%
------------------------------------------------------- Spot 62%
Major Supplier: ---------------------------------------------------------------------
Enron Major Suppliers:
Mobil Amoco
Pan Alberta Mobil
-------------------------------------------------------
------------------------------------------------------- ---------------------------------------------------------------------
Peak day sendout (MCF) 958,468 Peak day sendout (MCF) 27,259
Heating degree-days 6,557 Heating degree-days 4,670
------------------------------------------------------- ---------------------------------------------------------------------
Gas storage capacity (BCF):
Gas storage capacity (BCF) Leased .7
Leased 9.0 ---------------------------------------------------------------------
------------------------------------------------------- ---------------------------------------------------------------------
MICHIGAN GAS UTILITIES
-------------------------------------------------------
Average cost of purchased gas ($/MCF) $2.91
-------------------------------------------------------
Supply mix:
Contract 97%
Spot 3% GAS TARIFF SALES VOLUMES
------------------------------------------------------- ---------------------------------------------------------------------
Major suppliers: Residential Commercial Industrial Other
ANR Pipeline ---------------------------------------------------------------------
Consumers Power Missouri Public Service 65% 25% 4% 6%
Michigan Consolidated Gas Company Peoples Natural Gas 57 29 13 1
Panhandle Eastern Pipeline Michigan Gas Utilities 60 25 15 --
Trunkline Gas Company Northern Minnesota
------------------------------------------------------- Utilities 31 31 38 --
Peak day sendout (MCF) 292,838 West Virginia Power 43 16 2 39
Heating degree-days 6,604 Kansas Public Service 65 35 -- --
------------------------------------------------------- ---------------------------------------------------------------------
Gas storage capacity (BCF) ---------------------------------------------------------------------
Owned 3.6
Leased 5.2
-------------------------------------------------------
TOTAL STORAGE CAPACITY 8.8
-------------------------------------------------------
-------------------------------------------------------
WEST VIRGINIA POWER
-------------------------------------------------------
Average cost of purchased gas ($/MCF) $2.67
-------------------------------------------------------
Supply mix:
Contract 76%
Spot 24%
-------------------------------------------------------
Major suppliers:
West Virginia Independent Producers
Cabot Oil and Gas Marketing
-------------------------------------------------------
-------------------------------------------------------
Peak day sendout 42,500
Heating degree-days 5,093
-------------------------------------------------------
-------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit 99(c)
UTILICO GROUP GENERATING PROJECTS
----------------------------------------------------------------------------------------------------------------------------------
PERCENT CAPACITY(a)
PROJECT TYPE OF INVESTMENT OWNED (MEGAWATTS) FUEL DATE IN SERVICE
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Mega Renewables G.P. General partnership 49.75% 12.2 Hydro Spring 1987(b)
(California - 4 projects)
----------------------------------------------------------------------------------------------------------------------------------
Topsham Hydro Partners Leveraged lease 50% 13.9 Hydro October 1987
(Maine)
----------------------------------------------------------------------------------------------------------------------------------
Stockton CoGen Company General partnership 50% 49.9 Coal March 1988(c)
(California)
----------------------------------------------------------------------------------------------------------------------------------
Westwood Energy Properties Limited partnership 38% 29.25 Waste coal July 1988
L.P. (Pennsylvania)
----------------------------------------------------------------------------------------------------------------------------------
BAF Energy L.P. (California) Limited partnership 23.1% 111 Natural Gas May 1989
----------------------------------------------------------------------------------------------------------------------------------
Rumford Cogeneration Limited partnership 24.3% 75 Coal and May 1990
Company L.P. (Maine) Waste wood
----------------------------------------------------------------------------------------------------------------------------------
Koma Kulshan Associates Limited partnership 49.75% 13.7 Hydro October 1990
(Washington)
----------------------------------------------------------------------------------------------------------------------------------
Badger Creek Limited Limited partnership 49.75% 46.6 Natural gas April 1991
(California)
----------------------------------------------------------------------------------------------------------------------------------
McKittrick Limited Limited partnership 49.75% 45.4 Natural gas October 1991
(California)
----------------------------------------------------------------------------------------------------------------------------------
Live Oak Limited (California) Limited partnership 50% 45.8 Natural gas April 1992
----------------------------------------------------------------------------------------------------------------------------------
Lockport Energy Associates, Limited partnership 22.56% 168.8 Natural gas December 1992
L.P. (New York)
----------------------------------------------------------------------------------------------------------------------------------
Orlando Cogen Limited, L.P. Limited partnership 50% 120 Natural gas September 1993
(Florida)
----------------------------------------------------------------------------------------------------------------------------------
Jamaica Private Power Company Limited liability 21% 60 Diesel June 1996
(Jamaica) company (Est.)
----------------------------------------------------------------------------------------------------------------------------------
<FN>
(a) Total capacity, net of power consumed in generation.
(b) Interest acquired by UtilCo Group in June 1989.
(c) Interest acquired by UtilCo Group in December 1988.
</TABLE>
