<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
<TABLE>
<C> <S>
(MARK ONE) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
/X/ EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
</TABLE>
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER: 1-3562
------------------------
UTILICORP UNITED INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
DELAWARE 44-0541877
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification
No.)
</TABLE>
20 West Ninth Street, Kansas City, Missouri 64105
(Address of principal executive offices)
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
Convertible Subordinated Debentures, New York Stock Exchange
6-5/8%, due July 1, 2011
8-7/8% Cumulative Monthly Income Preferred Securities, New York Stock Exchange
Series A, due June 12, 2025
</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 Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
The aggregate market value of the voting stock held by non-affiliates of the
Registrant, based upon the closing sale price of the Common Stock on March 15,
1999 as reported on the New York Stock Exchange, was approximately
$2,132,635,622. Shares of Common Stock held by each officer and director and by
each person who owns 5% or more of the outstanding Common Stock have been
excluded in that such persons may be deemed to be affiliates. This determination
of affiliate status is not necessarily a conclusive determination for other
purposes.
<TABLE>
<CAPTION>
TITLE OUTSTANDING (AT MARCH 15, 1999)
- ------------------------------------------------------ ------------------------------------------------------
<S> <C>
Common Stock, par value $1.00 per share 93,605,985
- --------------------------------------------------------------------------------------------------------------
Documents Incorporated by Reference: Where Incorporated:
1998 Annual Report to Shareholders Part 2
Proxy Statement for 1999 Annual Shareholders Meeting Part 3
</TABLE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
INDEX
<TABLE>
<CAPTION>
PAGE
-----
<S> <C> <C>
PART 1
Item 1 Business............................................................................ 3
Item 2 Properties.......................................................................... 16
Item 3 Legal Proceedings................................................................... 19
Item 4 Submission of Matters to a Vote of Security Holders................................. 19
PART 2
Item 5 Market for Registrant's Common Equity and Related Stockholder
Matters........................................................................... 20
Item 6 Selected Financial Data............................................................. 21
Item 7 Management's Discussion and Analysis of Financial Condition and Results of
Operations........................................................................ 21
Item 7a Quantitative and Qualitative Disclosures about Market Risk.......................... 21
Item 8 Financial Statements and Supplementary Data......................................... 21
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial
Disclosure........................................................................ 21
PART 3
Item 10 Directors and Executive Officers of the Company..................................... 21
Item 11 Executive Compensation.............................................................. 21
Item 12 Security Ownership of Certain Beneficial Owners and Management...................... 21
Item 13 Certain Relationships and Related Transactions...................................... 21
PART 4
Item 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................... 22
INDEX TO EXHIBITS.......................................................................................... 26
SIGNATURES................................................................................................. 29
</TABLE>
2
<PAGE>
PART 1
ITEM 1. BUSINESS.
ORGANIZATION AND HISTORY
UtiliCorp United Inc. (the company, which may be referred to as we, us, or
our) is a multinational energy solutions provider. We conduct business through
the following business segments:
- REGULATED BUSINESSES--includes our domestic utility generation,
distribution and transmission businesses. Regulated businesses also
includes appliance repair/servicing and limited gas marketing businesses.
- AQUILA ENERGY--includes our natural gas and electricity marketing and
trading businesses, and Aquila Gas Pipeline Corporation, a publicly traded
natural gas gathering, processing and transportation company.
- INTERNATIONAL--includes our investments in an electric distribution
company in Australia, 79% owned UnitedNetworks Limited, (an electric
transmission company) in New Zealand, a gas transportation and risk
merchant company in the United Kingdom and an electric utility in Canada.
OUR STRATEGY
Our strategy is to operate energy delivery networks and to be a leading
energy merchant in the markets in which we compete. We believe this strategic
focus positions us to compete effectively in a deregulated energy marketplace.
The key elements of our strategy include:
- ALIGNMENT OF BUSINESSES TO ADDRESS A CHANGING COMPETITIVE ENVIRONMENT. We
believe that our distinct, yet inter-related, business groups enable us to
better manage our operations in the changing marketplace in which we
operate. Our corporate structure allows us to manage each of these
businesses individually, improving our ability to maximize their
profitability while providing low cost, high quality energy and energy
related products and services to our customers.
- PURSUIT OF STRATEGIC MERGERS, ACQUISITIONS, ALLIANCES, JOINT VENTURES AND
PARTNERSHIPS. Growth through mergers and acquisitions has been a major
part of our strategy for more than a decade. We believe that our
approximately $2.7 billion of investments in mergers and acquisitions has
played an integral role in establishing us as a leading diversified energy
provider. Most recently, we have completed several transactions to enhance
our operations in New Zealand and on March 11, 1999 submitted a winning
bid for a gas utility in Australia.
- IMPROVE OPERATIONAL EXCELLENCE. We constantly seek to improve our
operational performance. Over the last several years we have consolidated
operations of our domestic electric and natural gas distribution
businesses. As an example, our Regulated Businesses group is implementing
a single billing and accounting system for all of our domestic regulated
utilities in eight states. We have reduced the number of field offices
from 129 to 57, resulting in the elimination of 380 positions. We have
developed an energy marketing, trading and risk management system at
Aquila that will support substantially greater marketing and trading
volumes without the need for material additional investment.
- FOCUSED INTERNATIONAL OPERATIONS. Our International group is focused on
seeking early entry into markets that provide a combination of stable and
attractive political and economic environments and markets open or opening
to competition in electric or natural gas sales. As an example, we were
the first non-Australian company to invest in and manage an Australian
electric distribution company. As owners and managers of our international
operations, we seek to
3
<PAGE>
transfer our domestic knowledge and skills to improve the performance of
those operations. At the same time, we benefit from experience gained in
new, competitive international marketplaces, and we are using the
knowledge gained overseas to better position ourselves for domestic
deregulation.
- RISK MANAGEMENT. In order to compete effectively and profitably in energy
marketing and trading, we have an independent trading control officer who
reports directly to our President and also reports independently to the
Board of Directors. We closely monitor our operations and have written
policies and established trading limits. We have developed proprietary
risk management software which we license to other companies.
OUR COMPETITIVE STRENGTHS
We believe that we have developed substantial competitive strengths that
will enable us to continue to successfully execute our strategy. These strengths
include:
- Low cost, non-nuclear electric and natural gas utility businesses focused
on superior customer service.
- Market-leading position in energy marketing and trading.
- Experienced management team whose compensation is directly tied to
shareholder value.
- Proven risk management policies and procedures to limit exposure to
commodity market positions.
- Successful operation of competitive non-regulated businesses
- International operations in New Zealand, Australia, the United Kingdom,
and Canada from which we believe we have gained valuable experience in
competitive markets.
- Proven track record of quickly and successfully integrating domestic and
international mergers and acquisitions.
MERGERS & ACQUISITIONS
ST. JOSEPH LIGHT & POWER
In March 1999, we signed a definitive agreement with St. Joseph Light &
Power Company to merge in a transaction valued at approximately $270 million.
The agreement is subject to approvals by St. Joseph shareholders, and by state
and federal regulatory agencies. The merger is expected to be completed sometime
in mid-2000.
MULTINET GAS/IKON ENERGY
In March 1999, we and an Australian partner made a successful bid of $1.26
billion to acquire the natural gas utility Multinet Gas/Ikon Energy from the
State of Victoria, Australia. The acquisition is expected to be completed by
April 1999, with our ownership interest at 25.5%.
BUSINESS GROUP SUMMARY
Segment information for the three years ended December 31, 1998 is
incorporated by reference to pages 56 through 58 of our 1998 Annual Report to
Shareholders.
4
<PAGE>
I. REGULATED BUSINESSES
ELECTRIC OPERATING STATISTICS
The following table summarizes Regulated Businesses' sales, volumes and
customers for electric generation, transmission and distribution businesses.
<TABLE>
<CAPTION>
1998-1994
1998 1997 1996 1995 1994 CAGR*
--------- --------- --------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Sales (in millions)
Residential...................................... $ 244.8 $ 232.1 $ 227.3 $ 219.5 $ 211.4 3.7%
Commercial....................................... 161.3 154.5 147.3 142.0 140.7 3.5%
Industrial....................................... 74.8 73.6 70.4 67.9 66.4 3.0%
Other............................................ 46.7 97.2 74.3 60.7 57.6 (5.1)%
--------- --------- --------- --------- ---------
Total.......................................... $ 527.6 $ 557.4 $ 519.3 $ 490.1 $ 476.1 2.6%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Volumes (Gigawatt Hours (GWH)-000's)
Residential...................................... 3,169 2,942 2,897 2,758 2,639 4.7%
Commercial....................................... 2,585 2,409 2,308 2,236 2,190 4.2%
Industrial....................................... 1,779 1,727 1,660 1,608 1,535 3.8%
Other............................................ 905 1,390 1,939 1,372 1,230 (7.4 )%
--------- --------- --------- --------- ---------
Total.......................................... 8,438 8,468 8,804 7,974 7,594 2.7%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Customers
Residential...................................... 320,740 313,598 308,271 302,857 297,801 1.9%
Commercial....................................... 48,800 48,012 46,651 47,378 46,470 1.2%
Industrial....................................... 305 290 286 288 285 1.7%
Other............................................ 3,560 3,590 3,606 3,556 3,545 .1%
--------- --------- --------- --------- ---------
Total.......................................... 373,405 365,490 358,814 354,079 348,101 1.8%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
- ------------------------
* Compound annual growth rate
5
<PAGE>
GAS OPERATING STATISTICS
The following table summarizes Regulated Businesses' sales, volumes and
customers for gas distribution businesses.
<TABLE>
<CAPTION>
1998-1994
1998 1997 1996 1995 1994 CAGR*
--------- --------- --------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Sales (in millions)
Residential...................................... $ 379.4 $ 464.4 $ 429.1 $ 362.2 $ 356.4 1.6%
Commercial....................................... 161.2 205.8 192.6 153.9 156.9 .7%
Industrial....................................... 34.1 46.8 45.8 45.8 66.7 (15.4)%
Other............................................ 47.7 50.4 60.4 54.9 38.6 5.4%
--------- --------- --------- --------- ---------
Total.......................................... $ 622.4 $ 767.4 $ 727.9 $ 616.8 $ 618.6 .2%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Volumes--(Thousand Cubic Feet
(MCF)-000's)
Residential...................................... 66,564 77,594 81,698 76,461 71,208 (1.7 )%
Commercial....................................... 33,228 39,128 40,698 37,282 35,952 (2.0 )%
Industrial....................................... 8,631 11,059 10,944 12,901 18,439 (17.3 )%
Transportation................................... 140,499 158,937 166,562 178,114 135,924 .8%
Other............................................ 1,088 678 1,611 1,827 2,420 (18.1 )%
--------- --------- --------- --------- ---------
Total.......................................... 250,010 287,396 301,513 306,585 263,943 (1.3 )%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Customers
Residential...................................... 761,650 744,238 728,867 713,586 698,156 2.2%
Commercial....................................... 77,971 78,925 77,742 76,430 76,015 .6%
Industrial....................................... 1,982 2,491 3,725 3,790 3,878 (15.4 )%
Other............................................ 9,986 2,491 2,573 2,815 1,581 58.5%
--------- --------- --------- --------- ---------
Total.......................................... 851,589 828,145 812,907 796,621 779,630 2.2%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
- ------------------------
* Compound annual growth rate
REGULATION
The following is a summary of our pending rate case activity.
<TABLE>
<CAPTION>
TYPE OF DATE AMOUNT
RATE CASE DESIGNATION (IN MILLIONS) SERVICE REQUESTED REQUESTED
- --------------------------------------------------------- --------- ----------- -------------
<S> <C> <C> <C>
West Virginia............................................ Gas 10/30/98 $ 2.9
West Virginia............................................ Electric 12/15/98 $ 4.7
</TABLE>
In April 1998, we were ordered to reduce Missouri electric rates by $16.9
million plus increase depreciation expense by $5.8 million. This rate reduction
lowered 1998 EBIT by $16.3 million.
ENVIRONMENTAL
We are subject to various environmental laws. These include regulations
governing air and water quality and the storage and disposal of hazardous or
toxic wastes. We continually assess ways to ensure we comply with laws and
regulations on hazardous materials and hazardous waste and remediation
activities.
6
<PAGE>
We own or previously operated 29 former manufactured gas plants (MGP's)
which may, or may not, require some form of environmental remediation. We have
contacted appropriate federal and state agencies and are working to determine
what, if any, specific cleanup activities these sites may require.
As of December 31, 1998, we estimate cleanup costs on our identified MGP
sites to be $10.0 million. This estimate could change materially when we have
investigated further. It could also be affected by the actions of environmental
agencies and the financial viability of other responsible parties. Ultimate
liability also may be affected significantly if we are held responsible for
parties unable to contribute financially to the cleanup effort.
We have received favorable rate orders that enable us to recover
environmental cleanup costs in certain jurisdictions. In other jurisdictions,
there are favorable regulatory precedents for recovery of these costs. We are
also pursuing recovery from insurance carriers and other potentially responsible
parties.
In December 1996, the U.S. Environmental Protection Agency (EPA) published
its final rule for nitrous oxide (NOx) emissions as required by the Clean Air
Act Amendments of 1990. The new NOx regulations require that we install
additional emissions control equipment at one of our power plants by January 1,
2000.
In October 1998, the EPA published new air quality standards to further
reduce the emission of NOx. These more strict standards will require us to
install new equipment on our baseload coal units in Missouri that we estimate
will cost $35 million. The ultimate cost is under debate and subject to change.
The new standards as written are effective in May 2003.
We do not expect final resolution of these environmental matters to have a
material adverse effect on our financial position or results of operations.
SEASONAL VARIATIONS OF BUSINESS
Our utility and independent power project businesses are weather-sensitive.
We have both summer and winter peaking utility assets to reduce dependence on a
single peak season. The table below shows peak times for our utility businesses.
<TABLE>
<CAPTION>
JURISDICTION PEAK
- --------------------------------------------- ------------------------------
<S> <C>
Gas utility operations November through March
Missouri, Kansas and Colorado electric July and August
West Virginia electric November through March
</TABLE>
II. AQUILA ENERGY
WHOLESALE ENERGY MARKETING
Aquila's wholesale energy marketing business is conducted through various
operating units, collectively referred to as Energy Marketing. Energy Marketing
is a gas and power marketing company with a marketing, supply and transportation
network consisting of relations with gas producers, local distribution
companies, and end-users throughout the United States and Canada. Energy
Marketing adds value for customers by leveraging its national position in
financial deal structuring in gas and power marketing. It provides services such
as complex fuel supply arrangements, energy management services and project
development focused on control of mid-stream energy assets. For the five years
ended December 31, 1998, Energy Marketing had marketing volumes of 9.6, 6.8,
3.5, 1.9, and 1.4 billion cubic feet a day (BCF/d), respectively.
In 1995, Energy Marketing began selling electricity to wholesale customers,
much as it markets natural gas. Aquila expects that the electricity marketing
industry will continue to expand rapidly as
7
<PAGE>
liquidity and maturity increases. Aquila's wholesale power sales have grown from
129,000 megawatt hours (MWH) in 1995 to 121.2 million MWH in 1998, ranking it
third among the nation's largest volume power marketers.
Energy Marketing utilizes certain types of fixed-price contracts in
connection with its natural gas and power marketing businesses. These include
contracts that commit us to purchase or sell natural gas and other commodities
at fixed prices in the future (i.e., fixed-price forward purchase and sales
contracts), futures and options contracts traded on the NYMEX and swaps and
other types of financial instruments traded in the over-the-counter financial
markets.
The availability and use of these types of contracts allows us to manage and
hedge our contractual commitments, reduce our exposure relative to the
volatility of cash market prices, take advantage of carefully selected arbitrage
opportunities via open positions, protect our investment in natural gas storage
inventories and provide price risk management services to our customers. We are
also able to secure additional sources of energy or create additional markets
for existing supply through the use of exchange for physical transactions
allowed by NYMEX. We refer to our domestic and Canadian natural gas and
electricity trading activities as price risk management activities. These are
reflected in the accompanying financial statements using the mark-to-market
method of accounting.
Although we generally attempt to balance our fixed-price physical and
financial purchase and sales contracts in terms of contract volumes and the
timing of performance and delivery obligations, net open positions often exist
or are established due to the origination of new transactions and our assessment
of, and response to, changing market conditions. We will occasionally create a
net open position or allow a net open position to continue when we believe,
based upon competitive information gained from our energy marketing activities,
that future price movements will be consistent with our net open position. When
we have a net open position, we are exposed to fluctuating market prices.
In addition to price risk movements, credit risk is also inherent in our
risk management activities. Our trading and marketing business is also exposed
to counterparty credit risk resulting from a counterparty not fulfilling its
contractual obligations. Our credit policies with regard to our counterparties
attempt to minimize overall credit risk. Our credit procedures include a
thorough review of potential counterparties' financial condition, collateral
requirements under certain circumstances, monitoring of net exposure to each
counterparty and the use of standardized agreements which allow for the netting
of positive and negative exposures associated with each counterparty. Our credit
policy is monitored and administered by a function independent of the trading
and marketing activities.
GAS GATHERING AND PROCESSING
Aquila Gas Pipeline (AQP) gathers and processes natural gas and natural gas
liquids. AQP owns and operates a 3,403-mile intrastate gas transmission and
gathering network and four processing plants that extract and sell natural gas
liquids.
Key operating statistics for AQP are presented in the table below.
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Natural gas throughput (million cubic feet per day(MMcf/d)).......... 475 483 493 506 371
Natural gas liquids produced (thousand barrels per day).............. 25 37 41 32 31
Pipeline miles owned................................................. 3,403 3,434 3,416 3,311 2,718
</TABLE>
Aquila Energy and AQP own 35% of the capital stock of Oasis Pipe Line
Company (Oasis) and have 280 MMcf/d of firm intrastate transportation capacity.
The 600-mile Oasis pipeline system spans the state of Texas and links Aquila's
gathering systems to the Waha, Texas hub and the Katy, Texas hub.
8
<PAGE>
In 1998, AQP entered into a joint venture ownership and operation agreement
with a third party in the Austin Chalk area in Texas to gather and transport the
natural gas produced from specified wells. The sales contract accounted for
approximately 2% of AQP's total natural gas sales in 1998.
In November 1998, we made a proposal to acquire the 18% of AQP's common
stock we do not already own for $8.00 per share. An independent committee of
AQP's Board of Directors is evaluating the proposal.
INDEPENDENT POWER PROJECTS
Aquila Energy participates in the ownership and operation of facilities in
the independent and wholesale power generation market. Consistent with the
company's overall strategy to minimize risk through diversification, Aquila
Energy has invested in generation facilities which are geographically diverse
and use a variety of fuels and proven technologies. Additionally, each project
is a producer of competitively priced wholesale power in its geographic region
and has a long-term market for its output. To date, Aquila Energy has made
investments in 17 projects located in seven states and Jamaica, with a total net
ownership of approximately 332 MW of generating capacity. A description and
listing of the power projects appears on page X of this report.
We anticipate further expansion or investment in the independent power
projects business through a newly formed entity focused on structuring and
obtaining control of mid-stream energy assets.
III. INTERNATIONAL
Our international operations are managed separately from the other two
business groups. However, these energy operations are consistent with either the
delivery network or energy merchant strategies. We manage our international
businesses with local management that reports separately to the company. The
normalized contribution to earnings before interest and taxes from international
businesses was 20.8%, 17.0%, and 25.2% of our total for the years ended December
31, 1998, 1997 and 1996, respectively. As of December 31, 1998, approximately
$1,655.0 million of our total assets relate to our international businesses. The
following discussion briefly describes our international businesses.
AUSTRALIA
We acquired an effective 49.9% ownership interest in United Energy Limited
(UEL), an electric distribution utility serving 546,000 customers in the state
of Victoria. As part of a management agreement between us and UEL, we manage the
utility for a fee as well as participate in its earnings.
In May 1998, UEL sold 42% of its common stock to the Australian public and
as a result, we recorded a $45.3 million gain. The partial sale to the public
reduced our effective ownership percentage to 29%. Concurrent with UEL's stock
offering, we bought an additional 5% in UEL from another company to bring our
ownership to 34%. Prior to the common stock sale, UEL repaid approximately $101
million in debt notes owed to us. The management agreement between us and UEL
remains in place.
UEL distributes and sells electricity with a majority of its sales earned
from the regulated distribution network business. The regulated distribution
sales and connection charges for access to its distribution system will be
reviewed by the Office of the Regulator General (OGR), with new rates becoming
effective for five years beginning January 1, 2001.
9
<PAGE>
The retail market in which UEL operates is being progressively opened to
competition, with all customers becoming contestable by January 1, 2001. The
following table shows the timing of electricity markets opening to competition
in Victoria:
<TABLE>
<CAPTION>
DATE OF
THRESHOLD ELIGIBILITY PERCENT OF MARKET CUSTOMER TYPE
- ---------------------------------- ----------------- ----------------------- --------------------------------------
<S> <C> <C> <C>
GREATER THAN 5MW.................. Dec 1994 22% Large heavy industrial
GREATER THAN 1MW.................. July 1995 7% Large commercial industrial
GREATER THAN 750MWh............... July 1996 12% Medium commercial/light industrial
GREATER THAN 160MWh............... July 1998 8% Small commercial
All remaining customers........... January 2001 51% Residential
</TABLE>
NEW ZEALAND
Through a series of transactions in 1998, we gained control of Power New
Zealand through the purchase of an additional 48% interest for $245 million,
increasing our ownership to 78.6%. Concurrent with this acquisition, we sold our
39.6% interest in New Zealand's WEL Energy Group, which we acquired throughout
1995, 1996, and 1997, and bought out our 21% minority partner in our New Zealand
subsidiary, UtiliCorp N.Z, Inc.
New Zealand's Electricity Industry Reform Act of 1998 requires all the
country's utilities to separate ownership of their lines (network) and supply
(generation and retail) businesses. Power New Zealand, with approximately 90% of
its assets and earnings in the lines area, in November 1998 announced its
intention to remain in the network business and to exit the supply business. It
also agreed to purchase the Wellington-based lines assets of TransAlta New
Zealand Ltd. and to sell to TransAlta its retail electricity business serving
the Auckland area for a net expenditure by Power New Zealand of $238 million.
Because Power New Zealand's name transferred to TransAlta as part of the retail
business TransAlta acquired, the network business became UnitedNetworks Limited
on January 1, 1999. Also in 1998, Power New Zealand agreed to purchase the
electric line assets of neighboring power company TrustPower Limited for
approximately $261 million. The assets became part of a greater network which
includes parts of metropolitan Auckland and other areas in the central and
southern regions of New Zealand's North Island. The TrustPower transaction
closed January 1999. Completion of the TransAlta and TrustPower transactions
created the country's largest electricity distribution network, serving about
468,000 customers.
UNITED KINGDOM
We market transportation/shipping and balancing services to gas suppliers.
The fees we collect are priced as a unit per volume consumed. The gas markets in
the United Kingdom are fully competitive with end user customers being able to
choose their gas supplier. The deregulation of the gas markets resulted in many
new retail gas suppliers competing for the approximately 19 million gas
customers in the United Kingdom. As of December 31, 1998, we had approximately 1
million indirect customers, an increase of 900,000 customers since December 31,
1997.
In early 1999 we applied for our electricity supply license. Also this year,
we will begin trading electricity and offering a bundled electricity supply
service to our customers.
We have developed a European expansion plan and anticipate leveraging our UK
operations to begin marketing energy, as deregulation allows, on the European
Continent in 1999.
In June 1998, we paid $25.6 million to a third party to cancel two
take-or-pay contracts and related guarantees effective April 1, 1998, that
required us to take gas at significantly above-market prices until 2005. Between
1995 and 1997, we reserved $19.0 million against the estimated future losses on
these contracts, resulting in a "One Time" net settlement loss of $6.6 million.
10
<PAGE>
In July 1998, we lost a long-standing dispute with one of our previous
suppliers related to a take-or-pay gas supply contract. We were arguing that the
supplier did not make proper deliveries pursuant to the supply contract and
further materially breached the contract. Accordingly we began paying the
supplier the prevailing market prices which were lower than the contract price.
The difference between the two prices accumulated to approximately $38.0
million, an amount we had previously recorded as a liability.
A court ruling required us to pay this $38.0 million price difference along
with interest of $6.8 million that accumulated from the date the contract
invoices were due. This interest payment was recorded as a one-time loss. We are
appealing the court's decision and are seeking recovery of the $44.8 million.
CANADA
We own West Kootenay Power Ltd. (WKP), a hydro-electric utility in British
Columbia, Canada. WKP has four hydro-electric generation facilities with a
capacity of 205 megawatts and 962 miles of transmission lines that serve
approximately 86,000 customers in south central British Columbia. WKP generates
about half of its power requirements and purchases the remaining requirements
through power contracts.
The following table summarizes the sales, volumes and customers of WKP.
<TABLE>
<CAPTION>
1998-
1994
1998 1997 1996 1995 1994 CAGR*
--------- --------- --------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sales (in millions)
Residential................................................ $ 34.3 $ 36.2 $ 37.0 $ 32.9 $ 34.4 (.1)%
Commercial................................................. 18.1 18.8 19.7 19.1 16.6 2.2%
Industrial................................................. 8.2 8.5 9.4 9.4 8.7 (1.5 )%
Other...................................................... 26.4 26.3 26.8 26.2 21.2 5.6%
--------- --------- --------- --------- ---------
Total.................................................... $ 87.0 $ 89.8 $ 92.9 $ 87.6 $ 80.9 1.8%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Volumes (MWH 000s)
Residential................................................ 935 943 990 920 873 1.7%
Commercial................................................. 484 474 467 440 421 3.5%
Industrial................................................. 263 266 313 319 362 (7.7 )%
Other...................................................... 899 874 909 892 869 .9%
--------- --------- --------- --------- ---------
Total.................................................... 2,581 2,557 2,679 2,571 2,525 .6%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Customers
Residential................................................ 76,172 74,934 73,413 71,844 70,142 2.1%
Commercial................................................. 8,378 8,195 8,041 7,888 7,974 1.2%
Industrial................................................. 34 36 37 36 36 (1.4 )%
Other...................................................... 1,054 1,060 1,045 1,019 927 3.3%
--------- --------- --------- --------- ---------
Total.................................................... 85,638 84,225 82,536 80,787 78,313 2.3%
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
* COMPOUND ANNUAL GROWTH RATE
WKP is regulated by the British Columbia Utilities Commission. The
Commission approved renewal of the incentive based rate setting mechanism for
1999. This mechanism was the first of its kind for electric utilities in Canada
and was the result of a negotiated settlement with customers and regulators. The
mechanism calls for equal sharing of savings between the customer and WKP if WKP
performs over and above negotiated performance expectations.
11
<PAGE>
COMPETITION
DOMESTIC UTILITY OPERATIONS
Our domestic utility businesses operate in a regulated environment despite
various legislative deregulation efforts at the federal level. Industrial and
large commercial customers largely have access to energy sources so some of the
competitive pricing benefits have been transferred to these customers through
open access tariffs relating to transmission lines and pipelines. Without
federal legislation, competition at the retail level cannot form since the rules
will be different in each state. Based on our assessment of retail competition
possibilities, we reduced most retail activities, preferring to wait until the
market develops more fully.
ACCOUNTING IMPLICATIONS
We currently record the economic effects of regulation in accordance with
the provisions of Statement of Financial Accounting Standards No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulation." Accordingly, our
balance sheet reflects certain costs as regulatory assets. We expect that our
rates will continue to be based on historical costs for the foreseeable future.
If we discontinued applying SFAS No. 71, we would make adjustments to the
carrying value of our regulatory assets. Total net regulatory assets at December
31, 1998 were $96.5 million.
ENERGY MARKETING
Our energy marketing businesses operate in a fully competitive environment
that rewards participants on price, service and execution. Our energy marketing
businesses compete for customers with some of the largest utility and energy
companies in North America. The industry is premised on large volume sales with
relatively low margins. Companies that operate in this industry must fully
understand the price sensitivity and volatility of commodities. The public
became more aware of some of the risks associated with this industry when a
number of companies announced sudden losses resulting from the June price spike
in electricity. We expect price volatility and we expect events like the June
price spike to recur.
12
<PAGE>
OUR EXECUTIVE TEAM
<TABLE>
<CAPTION>
NAME AGE POSITION
- ----------------------------------------------------- --- -----------------------------------------------------
<S> <C> <C>
Richard C. Green, Jr. (Rick) 44 Chairman of the Board and Chief Executive Officer
Robert K. Green (Bob) 37 President and Chief Operating Officer
James G. Miller (Jim) 50 Senior Vice President, Energy Delivery
Charles K. Dempster (Chuck) 56 Senior Vice President; Chairman and Chief Executive
Officer, Aquila Energy Corporation
Edward A. Mills (Ed) 39 President and Chief Operating Officer, Aquila Energy
Corporation
Jon R. Empson 53 Senior Vice President, Regulatory, Legislative, and
Environmental Services
Robert L. Howell 58 Senior Vice President, Corporate Development (will
retire April 1, 1999)
Sally C. McElwreath 58 Senior Vice President, Corporate Communications
Leo E. Morton 53 Senior Vice President, Human Resources and Operations
Support
Dale J. Wolf 59 Vice President, Finance, Treasurer and Corporate
Secretary
James S. Brook (Jim) 49 Vice President, Controller and Chief Accounting
Officer
INTERNATIONAL
Donald G. Bacon (Don) 61 President, West Kootenay Power; Chief Executive
Officer, UnitedNetworks Limited
Charles K. Dempster (Chuck) 56 Interim Chairman and President, UtiliCorp U.K., Inc.
Robert K. Green (Bob) 37 Chairman, United Energy Limited; Chairman,
UnitedNetworks Limited
R. Paul Perkins 56 Senior Vice President, Australasia
Keith Stamm 38 Chief Executive Officer, United Energy Limited
</TABLE>
RICHARD C. GREEN, JR. (B.S. Business--Southern Methodist University)
Rick joined us in 1976 and held various financial and operating positions
between 1976 and 1982. In 1982, Rick was appointed Executive Vice President at
Missouri Public Service, the predecessor to UtiliCorp. In 1985, Rick became the
Chairman, President, and Chief Executive Officer and held those positions until
1996. Rick has been Chairman and Chief Executive Officer since 1996.
ROBERT K. GREEN (B.S. Engineering, Princeton University; J.D. Law,
Vanderbilt University)
Bob joined UtiliCorp in 1988 as Assistant Division Counsel and in 1989 was
appointed to Division Counsel. Between 1989 and 1992, Bob held executive level
positions at Missouri Public Service. In 1993, Bob was appointed Executive Vice
President and in 1996 assumed additional duties as
President. Bob also is the Chairman of
United Energy
13
<PAGE>
Limited, Ltd., a 34% owned foreign traded Australian company and UnitedNetworks
Limited, a 79% owned foreign traded New Zealand company.
JAMES G. MILLER (B.S. Electrical Engineering, M.B.A Management, University
of Wisconsin)
Jim joined the company in 1983 as President, Michigan Gas Utilities, a
company acquired by us in 198X. In 1991, Jim was appointed President, WestPlains
Energy and in 1995 was appointed Senior Vice President, Energy Delivery. Prior
to Jim's employment at UtiliCorp, Jim worked for Wisconsin Power and Light
Company in various financial and operating capacities.
CHARLES K. DEMPSTER (B.S. Civil Engineering, University of Houston)
Chuck joined us in 1993 as President of Aquila Energy Corporation. In 1994,
he was appointed Senior Vice President, Energy Resources. In 1995, Chuck became
Chairman and CEO of UtiliCorp U.K., Inc and in 1998, Chuck became Senior Vice
President, UtiliCorp; Chairman and Chief Executive Officer, Aquila Energy
Corporation. Prior to joining us, Chuck was President, Reliance Pipeline
Corporation between 1993 and 1987. Prior to 1987, Chuck held executive positions
at NICOR and Enron.
EDWARD A. MILLS (University of Texas, M.B.A., Finance, Rice University)
Ed joined our company in 1993 as Director of Risk Management and Trading,
Aquila. In 1998, Ed was appointed President and Chief Operating Officer, Aquila
Energy. Prior to joining our company, Ed held executive and management positions
at Fina Oil and Chemical Company, Texas Commerce Bank, and Springer Holding
Company.
JON R. EMPSON (B.A. Economics, Carleton College, M.B.A, Economics,
University of Nebraska at Omaha)
Jon joined our company in 1986 as Vice President, Regulation, Finance and
Administration. In 1993, Jon was appointed Senior Vice President, Gas Supply and
Regulatory Services and in 1996 he was appointed Senior Vice President,
Regulatory, Legislative and Environmental Services. Prior to joining UtiliCorp,
Jon worked for a predecessor company in various executive and management
positions for 7 years, held executive management positions of the Omaha Chamber
of Commerce and Omaha Economic Development Council and worked as an economist
with the Department of Housing and Urban Development.
SALLY C. MCELWREATH (B.A. Social Sciences, M.B.A. Public Relations, Pace
University)
Sally joined us in 1994 as Senior Vice President, Corporate Communications.
Prior to joining our company, Sally was Vice President, Corporate Communications
for MacMillan Inc. and for The Travel Channel; Director of Marketing
Communications for Trans World Airways and Manager of Corporate Communications
for United Airlines beginning in 1971. Prior to 1971, she held various positions
with ARCO and Sinclair Oil Corporation.
LEO E. MORTON (B.S. Mechanical Engineering, Tuskegee University; M.S.
Management, Massachusetts Institute of Technology)
Leo joined our company in 1994 as Senior Vice President, Operations Support
and was appointed to his current position in 1996. Prior to working for us, Leo
held executive and management positions in manufacturing and engineering for
AT&T beginning in 1973.
DALE J. WOLF (B.S. Business Administration, Fort Hays State University;
M.B.A Finance, University of Missouri)
Dale joined our company in 1962 as a staff accountant at Missouri Public
Service. Between 1962 and 1972, Dale held various accounting and finance
positions. In 1972, Dale was appointed Assistant Treasurer and in 1976,
Treasurer. In 1984, Dale was promoted to Vice President and Treasurer for
Missouri Public Service. When UtiliCorp was formed in 1985, Dale became its Vice
President, Finance and Treasurer. In 1989, Dale assumed the Corporate Secretary
responsibilities.
14
<PAGE>
JAMES S. BROOK (B.S. Commerce, University of Manitoba, Chartered Accountant;
M.B.A. University of Kansas)
Jim joined our company in 1976 as a financial assistant at West Kootenay
Power. In 1978, Jim was appointed to Manager, Financial Administration and in
1980, Jim was appointed as Chief Financial Officer. In 1990, Jim was appointed
to Senior Vice President, Administration at Missouri Public Service and in 1993
was appointed to his current position at Corporate.
DONALD G. BACON (B.S. Civil Engineering, University of Alberta)
Don joined our company in 1993 as President of West Kootenay Power. In 1997,
Don became Power New Zealand's Chief Executive Officer in addition to his
responsibilities in Canada. Prior to Don's employment with us, he was a Vice
President at TransAlta Utilities Corporation between 1988 and 1993 and in
various operating positions from 1975 and 1988.
R. PAUL PERKINS (B.A. International Relations, University of North Carolina)
Paul joined us in 1994 as Vice President, Corporate Development. Paul's
primary focus in Corporate Development was in international opportunities. In
1997, Paul was appointed Senior Vice President, Australia. Prior to joining
UtiliCorp, Paul was a regional manager for WMX Technologies between 1992 and
1994 focusing on Latin America and the Caribbean. Paul worked for Texaco Inc. as
a Division Manager, Supply and Trading for Latin America and West Africa between
1990 and 1992. Paul worked for Texaco between 1978 and 1990 in other
international capacities.
KEITH G. STAMM (B.S. Mechanical Engineering, University of Missouri at
Columbia; M.B.A. Finance, Rockurst College. Licensed professional engineer)
Keith joined our company in 1983 as a staff engineer at our Sibley Power
Plant. Between 1985 and 1995, Keith held various operating positions. In 1995,
Keith was promoted to Vice President, Energy Trading and in 1996, promoted to
Vice President and General Manager, Regulated Power. In 1997, Keith became the
Chief Executive Officer of United Energy Limited.
15
<PAGE>
ITEM 2. PROPERTIES.
We own electric production, transmission and distribution systems and gas
transmission and distribution systems throughout our service territories. We
also own gas gathering, processing and pipeline systems. Substantially all
utility plant assets in Michigan are mortgaged pursuant to an Indenture of
Mortgage and Deed of Trust dated July 1, 1951, as supplemented. Substantially
all of our Canadian utility plant is mortgaged under terms of a separate
indenture.
UTILITY FACILITIES
Our electric generation plants, as of December 31, 1998, are as follows:
<TABLE>
<CAPTION>
UNIT CAPABILITY NET
(KW NET, PER GENERATION
UNIT LOCATION YEAR INSTALLED HOUR) FUEL (MW HOURS)
- -------------------------- -------------------------- ------------------- --------------- --------- ------------
<S> <C> <C> <C> <C> <C>
MISSOURI:
Sibley #1 - #3 Sibley 1960, 1962, 1969 496,000 Coal 3,090,148
Ralph Green #3 Pleasant Hill 1981 74,000 Gas 35,100
Nevada Nevada 1974 20,000 Oil 1,117
Greenwood #1 - #4 Greenwood 1975 - 1979 247,000 Gas/Oil 200,524
KCI #1 and #2 Kansas City 1970 33,000 Gas 6,876
- ---------------------------------------------------------------------------------------------------------------------
KANSAS:
Judson Large #4 Dodge City 1969 143,000 Gas 386,481
Arthur Mullergren #3 Great Bend 1963 90,000 Gas 258,932
Cimarron River #1 -- #2 Liberal 1963, 1967 72,000 Gas 145,822
Clifton #1 -- #2 Clifton 1974 73,000 Gas/Oil 45,563
Jeffrey #1 -- #3 St. Mary's 1978, 1980, 1983 352,000 Coal 2,223,054
- ---------------------------------------------------------------------------------------------------------------------
COLORADO:
W.N. Clark #1 -- #2 Canon City 1955, 1959 40,000 Coal 220,789
Pueblo #6 Pueblo 1949 20,000 Gas 6,969
Diesel #'s 1,2,3,4,5 Pueblo 1964 10,000 Oil 837
Diesel #'s 1,2,3,4,5 Rocky Ford 1964 10,000 Oil 596
- ---------------------------------------------------------------------------------------------------------------------
CANADA:
No. 1 Lower Bonnington, BC 1925 42,000 Hydro 296,796
No. 2 Upper Bonnington, BC 1907 60,000 Hydro 437,944
No. 3 South Slocan, BC 1928 53,000 Hydro 428,771
No. 4 Corra Linn, BC 1932 50,000 Hydro 349,381
-------------------------- ------------------- --------------- --------- ------------
TOTAL 1,885,000 8,135,700
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
The following table shows the overall fuel mix and generation capability for
the past five years.
<TABLE>
<CAPTION>
SOURCE (MW) 1998 1997 1996 1995 1994
- ------------------------------------------------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Coal............................................. 888 889 885 875 868
Gas and oil...................................... 792 790 784 705 705
Hydro............................................ 205 205 205 205 205
--------- --------- --------- --------- ---------
Total generation capability................ 1,885 1,884 1,874 1,785 1,778
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
16
<PAGE>
At December 31, 1998, we had transmission and distribution lines as follows:
<TABLE>
<CAPTION>
LENGTH (POLE
DESCRIPTION MILES)
- -------------------------------------------------------------------------------- ------------
<S> <C>
Transmission lines.............................................................. 5,295
Overhead distribution lines..................................................... 21,043
Underground distribution lines.................................................. 6,976
------------
Total....................................................................... 33,314
------------
------------
</TABLE>
At December 31, 1998, our gas utility operations had 2,122 miles of gas
gathering and transmission pipelines and 24,056 miles of distribution mains and
service lines located throughout its service territories.
GAS PROCESSING AND GATHERING ASSETS
AQP owned and/or operated 11 active natural gas pipeline systems with an
aggregate length of approximately 3,403 miles. These pipelines do not form an
interconnected system. Set forth below is information with respect to AQP's
pipeline systems as of December 31, 1998:
<TABLE>
<CAPTION>
GAS THROUGHPUT AVG. DAILY GAS
MILES OF CAPACITY THROUGHPUT
PIPELINE (A)(B) (A)(B)(C)
GATHERING SYSTEMS LOCATION (A) (MMCF/D) (MMCF/D)
- ---------------------------------------------- ----------------- ----------- ----------------- -------------------
<S> <C> <C> <C> <C>
Southeast Texas/Katy.......................... SE Texas 2,338 732 381
Mentone....................................... W. Texas 13 60 --
Gomez......................................... W. Texas 11 40 --
Menard County................................. C. Texas 120 30 2
Maverick County............................... W. Texas 121 20 2
Rhoda Walker.................................. W. Texas 21 20 2
Panola County................................. E. Texas 23 8 1
Elk City...................................... SW Oklahoma 163 100 69
Mooreland..................................... NW Oklahoma 324 40 11
Brooks-Hidalgo--23%(d)........................ S. Texas -- -- 1
Dorado--40%................................... S. Texas 58 40 9
Benedum/Wilshire--20%......................... W. Texas 211 130 14
----- ----- ---
3,403 1,220 492
Fuel and Shrinkage............................ -- -- (17)
----- ----- ---
Total..................................... 3,403 1,220 475
----- ----- ---
----- ----- ---
</TABLE>
- ------------------------
(a) All mileage, capacity and volume information is approximate. Capacity
figures are management's estimates based on existing facilities without
regard to the present availability of natural gas.
(b) Gross gas throughput capacity is included at 100% while average gas
throughput is presented at the our present joint venture ownership interest.
(c) Excludes off-system marketing sales with average daily volumes of 795
MMcf/d sold from other companies' facilities
(d) In March 1998, Brooks-Hidalgo Joint Venture's ownership interests in
its assets were sold.
At December 31, 1998, we owned 35% of the capital stock of Oasis and the
right to transport 280 MMcf/d of natural gas on Oasis' pipeline, plus the
opportunity to utilize excess capacity on an interruptible basis. The Oasis
pipeline is a 600-mile, 36-inch diameter natural gas pipeline which connects
17
<PAGE>
the Waha, Texas hub to the Katy, Texas hub. The Oasis pipeline has a 1 Bcf/d of
throughput capacity. We use the equity method of accounting for this investment.
At December 31, 1997, AQP owned and/or operated an interest in four natural
gas processing plants. Set forth below is information with respect to AQP's
processing plants as of December 31, 1998:
<TABLE>
<CAPTION>
GAS THROUGHPUT GAS THROUGHPUT NGLS PRODUCTION
CAPACITY(A) (A),(B) (A),(B)
PROCESSING PLANTS (MMCF/D) (MMCF/D) (MBBLS/D)(D)
- ---------------------------------------------------------- ------------------- ------------------- -------------------
<S> <C> <C> <C>
La Grange, Texas.......................................... 230 165 20.2
Somerville, Texas......................................... 28 19 .5
Benedum, Texas 20%........................................ 125 14 .9
Elk City, Oklahoma........................................ 115 69 3.5
--- --- ---
Total owned plants.................................... 498 267 25.1
Katy, Texas(d)............................................ -- 173 --
--- --- ---
Total................................................. 498 440 25.1
--- --- ---
--- --- ---
</TABLE>
- ------------------------
(a) All capacity and volume information is approximate. Capacity figures are
management's estimates based on existing facilities without regard to the
present availability of natural gas.
(b) Volumes from joint ventures have been included at the present AQP
ownership interest.
(c) Thousands of barrels per day (MBbls/d).
(d) This plant is owned and operated by a third party from which AQP receives a
portion of the NGLs produced from gas AQP delivers to the plant. The plant
is included in this section for informational purposes to show the gas
throughput and NGLs production that AQP received utilizing the access to
this plant.
The availability of natural gas reserves to AQP depends on their development
in the area served by its pipelines and on AQP'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 AQP's systems.
18
<PAGE>
INDEPENDENT POWER PROJECTS
Information regarding the company's generating projects is set forth below.
<TABLE>
<CAPTION>
TYPE OF PERCENT CAPACITY
PROJECT & LOCATION INVESTMENT OWNED (MW)(A) FUEL DATE IN SERVICE
- ----------------------------- ----------------- ----------- ----------- -------------------- -------------------
<S> <C> <C> <C> <C> <C>
Mega Renewables G.P., 4 General 49.75% 12.2 Hydro Spring 1987(b)
projects in California partnership
Topsham Hydro Partners, Maine Leveraged lease 50 13.9 Hydro October 1987
Stockton CoGen Company, General 50 60.0 Coal March 1988(c)
California partnership
Westwood Energy Properties, Limited 38 29.25 Waste coal July 1988
Pennsylvania partnership
BAF Energy L.P., California Limited 23.1 120.0 Natural Gas May 1989
partnership
Rumford Cogeneration Company Limited 24.3 85.0 Coal and waste wood May 1990
L.P., Maine partnership
Koma Kulshan Associates, Limited 49.75 13.7 Hydro October 1990
Washington partnership
Badger Creek Limited, Limited 49.75 50.0 Natural gas April 1991
California partnership
McKittrick Limited, Limited 49.75 50.0 Natural gas October 1991
California partnership
Live Oak Limited, California Limited 50 50.0 Natural gas April 1992
partnership
Lockport Energy Associates, Limited 16.58 180.0 Natural gas December 1992
L.P., New York partnership
Orlando Cogen Limited, L.P., Limited 50 125.7 Natural gas September 1993
Florida partnership
Naheola Cogeneration LP, Limited 50 81.2 Black liquor solids, March 1993(d)
Alabama partnership coal, gas, wood
Jamaica Private Power Limited liability 24.09 60.0 Diesel January 1997
Company, Jamaica Company
</TABLE>
(a) Nominal gross capacity.
(b) Interest acquired by the company in June 1989.
(c) Interest acquired by the company in December 1988.
(d) Interest acquired by the company in May 1995.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders in the fourth
quarter of 1998.
19
<PAGE>
PART 2
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The company's common stock (par $1) is listed on the New York, Pacific and
Toronto stock exchanges under the symbol UCU. At December 31, 1998, the company
had 41,027 common shareholders of record. Information relating to market prices
of common stock and cash dividends on common stock is set forth in the table
below.
MARKET PRICE
<TABLE>
<CAPTION>
CASH
HIGH(A) LOW(A) DIVIDENDS(A)
----------- --------- -------------
<S> <C> <C> <C>
1998 QUARTERS
First....................................................................... $ 26.29 $ 23.33 $ .30
Second...................................................................... 26.33 23.21 .30
Third....................................................................... 26.25 22.63 .30
Fourth...................................................................... 24.46 22.87 .30
1997 QUARTERS
First....................................................................... $ 18.83 $ 17.00 $ .2933
Second...................................................................... 19.59 17.17 .2933
Third....................................................................... 20.59 19.33 .2933
Fourth...................................................................... 26.04 20.09 .2933
</TABLE>
- ------------------------
(a) All per share amounts have been restated for the 3-for-2 stock split.
20
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
----------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
IN MILLIONS (EXCEPT PER SHARE)
Sales............................................. $ 12,563.4 $ 8,926.3 $ 4,332.3 $ 2,792.6 $ 2,398.1
Income from operations............................ 240.8 243.3 225.8 227.1 228.0
Net income........................................ 132.2 122.1 105.8 79.8 94.4
Earnings available for common shares.............. 132.2 121.8 103.7 77.7 91.4
Basic earnings per common share (a)............... 1.65 1.51 1.46 1.15 1.39
Cash dividends per common share (a)............... 1.20 1.17 1.17 1.15 1.13
Total assets...................................... 5,991.5 5,113.5 4,739.8 3,885.9 3,111.1
Short-term debt (including current maturities).... 484.4 263.4 277.7 303.7 321.2
Long-term debt.................................... 1,375.8 1,358.6 1,470.7 1,355.4 976.9
Company-obligated mandatorily redeemable preferred
securities of a partnership..................... 100.0 100.0 100.0 100.0 --
Preference and preferred stock.................... -- -- 25.0 25.4 25.4
Common shareholders' equity....................... 1,446.3 1,163.6 1,158.0 946.3 906.8
</TABLE>
- ------------------------
(a) All per share amounts have been restated for the 3-for-2 stock split.
Items between years that impact comparability are described and are
incorporated by reference on page 27 in the company's 1998 Annual Report to
Shareholders.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION.
The information required by this item is incorporated by reference to pages
27 through 39 in the company's 1998 Annual Report to Shareholders.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The information required by this item is incorporated by reference to pages
36 and 37 in the company's Annual Report to Shareholders.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is incorporated by reference to pages
40 through 60 of the company's 1998 Annual Report to Shareholders.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART 3
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 appear in our proxy statement and is
hereby incorporated by reference in this Annual Report on Form 10-K. For
information with respect to the executive officers of the company, see
"Executive Officers of the Registrant" following Item 1 in Part 1 of this Form
10-K.
21
<PAGE>
PART 4
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
<TABLE>
<CAPTION>
PAGE NO.
-----------
<S> <C>
Consolidated Statements of Income for the three years ended December 31, 1998...... *
Consolidated Balance Sheets at December 31, 1998 and 1997.......................... *
Consolidated Statements of Common Shareowners' Equity for the three years ended
December 31, 1998................................................................ *
Consolidated Statements of Comprehensive Income for the three years ended December
31, 1998......................................................................... *
Consolidated Statements of Cash Flows for the three years ended December 31,
1998............................................................................. *
Notes to Consolidated Financial Statements......................................... *
Report of Independent Public Accountants........................................... *
</TABLE>
- ------------------------
* Incorporated by reference to pages 40 through 60 of the company's 1998 Annual
Report to Shareholders.
(2) FINANCIAL STATEMENT SCHEDULE
<TABLE>
<S> <C>
Report of Independent Accountants on Financial Statement Schedule
II................................................................ 24
Valuation and Qualifying Accounts for the years 1998, 1997 and
1996............................................................ 25
</TABLE>
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 *
The following exhibits relate to a management contract or compensatory plan
or arrangement:
<TABLE>
<S> <C>
10(a)(2) UtiliCorp United Inc. Deferred Income Plan.
10(a)(3) UtiliCorp United Inc. Amended and Restated 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) Severance Compensation Agreement.
10(a)(7) Executive Severance Payment Agreement.
10(a)(8) Split Dollar Agreement.
10(a)(9) Supplemental Retirement Agreement.
10(a)(11) UtiliCorp United Inc. Life Insurance Program for Officers.
10(a)(12) Summary of Terms and Conditions of Employment of Charles K.
Dempster.
10(a)(13) Supplemental Executive Retirement Plan, Amended and Restated.
10(a)(14) Employment Agreement for Richard C. Green, Jr.
10(a)(15) Employment Agreement for Robert K. Green.
10(a)(16) Capital Accumulation Plan.
10(a)(17) Supplemental Contributory Retirement Plan.
</TABLE>
- ------------------------
* Incorporated by reference to the Index to Exhibits.
22
<PAGE>
(b) Reports on Form 8-K
A current report on Form 8-K dated November 13, 1998, filed on November 16,
1998, with respect to Item 5 and Item 7 was filed with the Securities and
Exchange Commission by the Registrant.
A current report on Form 8-K dated December 10, 1998, filed on December 14,
1998, with respect to Item 7 was filed with the Securities and Exchange
Commission by the Registrant.
23
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Shareholders of UtiliCorp United Inc.:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements for 1998, 1997 and 1996 described on
page 60 of UtiliCorp United Inc.'s Annual Report to shareholders, which is
incorporated by reference in this Form 10-K, and have issued our report
thereon dated February 1, 1999. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The Financial
Statement Schedule listed in Item 14(a)2 is the responsibility of the
company's management and is presented for the purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic consolidated 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
consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Kansas City, Missouri
February 1, 1999
24
<PAGE>
UTILICORP UNITED INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998
(IN MILLIONS)
<TABLE>
<CAPTION>
COLUMN E
COLUMN B COLUMN D -------------------
--------------- COLUMN C -------------- DEDUCTIONS FROM COLUMN F
COLUMN A BEGINNING ------------------- ADDITIONS RESERVES FOR -----------------
- ------------------------------- BALANCE AT PURCHASE OF A CHARGED TO PURPOSES FOR ENDING BALANCE
DESCRIPTION DECEMBER 31 BUSINESS EXPENSE WHICH CREATED AT DECEMBER 31
- ------------------------------- --------------- ------------------- -------------- ------------------- -----------------
<S> <C> <C> <C> <C> <C>
Price Risk Management credit
and service reserves:
1998......................... $ 60.4 -- -- 7.9 $ 52.5
1997......................... $ 57.2 -- 3.2 -- $ 60.4
1996......................... $ 70.6 -- -- 13.4 $ 57.2
Reserve for United Kingdom gas
contracts
1998......................... $ 19.0 -- 6.6 25.6 $ --
1997......................... $ 14.0 -- 5.0 -- $ 19.0
1996......................... $ 11.0 -- 3.0 -- $ 14.0
</TABLE>
25
<PAGE>
UTILICORP UNITED INC.
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------------ ----------------------------------------------------------------------------------------------------
<S> <C>
*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) By-laws of the Company as amended. (Exhibit 3.1 on Form 10-Q for the quarter ended June 30, 1998.)
*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 3.2 on Form 10-Q for the quarter ended June 30, 1998.)
*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(b)(8) Seventh Supplemental Indenture, dated as of June 1, 1995. (Exhibit 4 to the Company's Form 10-Q for
the period ended June 30, 1995.)
*4(b)(9) Eighth Supplemental Indenture, dated as of October 1, 1996 (Exhibit 4(b)(9) to the company's Annual
Report on Form 10-K for the year ended December 31, 1996).
*4(b)(10) Ninth Supplemental Indenture, dated as of September 1, 1997 (Exhibit 4 to the company's quarterly
report on Form 10-Q for the period ended September 30, 1997).
*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.
</TABLE>
26
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------------ ----------------------------------------------------------------------------------------------------
<S> <C>
*4(d)(1) Indenture, dated as of June 1, 1995, Junior Subordinated Debentures. (Exhibit 4(d)(1) to the
company's Annual Report on Form 10-K for the year ended December 31, 1995.)
*4(d)(2) First Supplemental Indenture, dated as of June 1, 1995, Supplement to Indenture dated June 1, 1995.
(Exhibit 4(d)(2) to the company's Annual Report on Form 10-K for the year ended December 31,
1995.)
*4(e)] Form of Rights Agreement between UtiliCorp United Inc. and First Chicago Trust Company of New York,
as Rights Agent. (Exhibit 4 to the company's Form 10-Q for the period ended September 30, 1996.)
*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 & 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. Amended and Restated 1986 Stock Incentive Plan. (Exhibit 10.3 to the company's
Form 10-Q for the quarter ended June 30, 1998.)
*10(a)(4) UtiliCorp United Inc. Annual and Long-Term Incentive Plan. (Exhibit 10.4 to the Company's Form 10-Q
for the quarter ended June 30, 1998).
*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) Form of Severance Compensation Agreement between UtiliCorp United Inc., and certain Executives of
the Company. (Exhibit 10 (a)(7) to the company's Annual Report on Form 10-K for the year ended
December 31, 1995.)
*10(a)(7) 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)(8) Split Dollar Agreement dated as of June 12, 1985, between the Company and James G. Miller. (Exhibit
10(a)(10) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994.)
*10(a)(9) Supplemental Retirement Agreement dated as of January 27, 1983, between the Company and James G.
Miller. (Exhibit 10(a)(11) to the Company's Annual Report on Form 10-K for the year ended December
31, 1994.)
*10(a)(10) 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)(11) UtiliCorp United Inc. Life Insurance Program for Officers. (Exhibit 10 (a)(13) to the company's
Annual Report on Form 10-K for the year ended December 31, 1995.)
*10(a)(12) Summary of Terms and Conditions of Employment of Charles K. Dempster. (Exhibit 10 to the company's
quarterly report on Form 10-Q for the period ended March 31, 1996.)
*10(a)(13) Supplemental Executive Retirement Plan, Amended and Restated, effective as of January 1, 1998.
(Exhibit 10.1 on Form 10-Q for the quarter ended June 30, 1998.)
</TABLE>
27
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------------ ----------------------------------------------------------------------------------------------------
<S> <C>
*10(a)(14) Employment Agreement for Richard C. Green, Jr. (Exhibit 10.4 on Form 10-Q for the quarter ended June
30, 1998.)
*10(a)(15) Employment Agreement for Robert K. Green (Exhibit 10.5 on Form 10-Q for the quarter ended June 30,
1998.)
*10(a)(16) Capital Accumulation Plan, effective as of January 1, 1998. (Exhibit 10(a)(1) to the company's Form
10-Q for the quarter ended March 31, 1998.)
*10(a)(17) Supplemental Contributory Retirement Plan, effective as of January 1, 1998. (Exhibit 10(a)(2) to the
company's Form 10-Q for the quarter ended March 31, 1998.)
13 Annual Report to Shareholders for the year ended December 31, 1998
21 Subsidiaries of the Company.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
</TABLE>
- ------------------------
* Exhibits marked with an asterisk are incorporated by reference as indicated
pursuant to Rule 12(b)-23.
28
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, there unto duly authorized.
UTILICORP UNITED INC.
<TABLE>
<S> <C> <C>
By: /s/ RICHARD C. GREEN, JR.
----------------------------
Richard C. Green, Jr. Chairman of the Board of
Directors, Chief
Executive Officer (Principal
Executive Officer)
Date: March 25, 1999
</TABLE>
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<S> <C> <C>
By: /s/ RICHARD C. GREEN, JR.
----------------------------
Richard C. Green, Jr. Chairman of the Board of
Directors, Chief Executive
Officer (Principal Executive
Officer)
Date: March 25, 1999
By: /s/ ROBERT K. GREEN
----------------------------
Robert K. Green
President, Chief Operating
Officer and Director
Date: March 25, 1999
By: /s/ JAMES S. BROOK
----------------------------
James S. Brook
Vice President, Controller and
Chief Accounting Officer
Date: March 25, 1999
By: /s/ JOHN R. BAKER
----------------------------
John R. Baker
Director
Date: March 25, 1999
By: /s/ AVIS G. TUCKER
----------------------------
Avis G. Tucker
Director
Date: March 25, 1999
</TABLE>
29
<PAGE>
<TABLE>
<S> <C> <C>
By: /s/ ROBERT F. JACKSON
----------------------------
Robert F. Jackson
Director
Date: March 25, 1999
By: /s/ L. PATTON KLINE
----------------------------
L. Patton Kline
Director
Date: March 25, 1999
By: /s/ HERMAN CAIN
----------------------------
Herman Cain
Director
Date: March 25, 1999
By: /s/ IRVINE O. HOCKADAY,
JR.
----------------------------
Irvine O. Hockaday, Jr.
Director
Date: March 25, 1999
By: /s/ DR. STANLEY O.
IKENBERRY
----------------------------
Dr. Stanley O. Ikenberry
Director
Date: March 25, 1999
</TABLE>
30
<PAGE>
Exhibit 13
FIRST MOVER
FINANCIAL REVIEW
- --------------------------------------------------------------------------------
Consolidated Operations
This review of 1998 performance is organized by business segments, reflecting
the way we manage our businesses. Each business unit leader is responsible for
operating results expressed as earnings before interest and taxes (EBIT).
Therefore each segment discussion focuses on the factors affecting EBIT.
We make all decisions on finance, dividends and taxes at the corporate
level. We discuss those topics separately on a consolidated basis. Our main
financial performance objectives are: -
<TABLE>
<CAPTION>
1998
Objective Result
- -----------------------------------------------------------------------------
<S> <C> <C>
Earnings per share growth 8% 8.0%
Total 3-year return Exceed peer
to shareholders group average* 45.1%
Dividend growth 2% 2.3%
- --------------------------------------------------------------------------------
</TABLE>
* We compare our total return to that of 12 top-tier competitors that are
similar in terms of customers, employees and markets. In 1998 the peer
group had an average 3-year return of 40.9%.
A summary of our normalized EBIT by business segment is shown below.
<TABLE>
<CAPTION>
Long-Term
Future
Dollars in millions 1998 1997 1996 Growth Rate*
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Regulated Businesses $210.2 60.5% $197.5 $206.3 2%
Aquila Energy:
Aquila Gas Pipeline 18.6 5.4 51.8 51.4 3%
Aquila Marketing 20.5 5.9 18.4 (4.2) 20%+
Independent power projects 32.2 9.2 27.7 22.1 4%
- -----------------------------------------------------------------------------------------------------
Total Aquila Energy 71.3 20.5 97.9 69.3 20%
- -----------------------------------------------------------------------------------------------------
International:
Australia 22.3 6.5 27.0 38.3
Canada 22.0 6.3 26.2 27.7
New Zealand 21.4 6.2 9.9 11.6
United Kingdom 6.2 1.8 (5.6) 2.1
- -----------------------------------------------------------------------------------------------------
Total International 71.9 20.8 57.5 79.7 6%-20%
- -----------------------------------------------------------------------------------------------------
Corporate and other (6.2) (1.8) (13.8) (39.0)
- -----------------------------------------------------------------------------------------------------
Total Normalized EBIT $347.2 100.0% $339.1 $316.3 6.5%
- -----------------------------------------------------------------------------------------------------
Normalized Earnings Per Share--Diluted $1.62 $1.50 $1.39 8%
- -----------------------------------------------------------------------------------------------------
</TABLE>
* Management estimate.
<TABLE>
Earnings Per Share Growth
<S> <C> <C> <C>
98 +8%........... 1.62
97 +8%........... 1.50
96.............................................. 1.39
0 .50 1.00 1.50
- -----------------------------------------------------
DILUTED AND NORMALIZED--DOLLARS
</TABLE>
Our goal is to grow earnings per share by 8% per year, which is significantly
faster than the industry average. We set this goal in mid-1997 and have achieved
it two years in a row.
<TABLE>
<CAPTION>
CAPITAL EMPLOYED
<S> <C> <C> <C>
98............................................ 3,406.5
97............................................ 2,885.6
96............................................ 3,031.4
0 1,000 2,000 3,000
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Capital employed represents the dollars invested in the
business. Our capital employed increased more than $500 million in 1998 due to
recent investments in New Zealand and additional working capital.
27
<PAGE>
THE MAIN FACTORS SHAPING 1998 RESULTS
Comparison to 1997 Normalized Diluted Earnings Per Share
<TABLE>
<CAPTION>
NEGATIVE FACTORS: POSITIVE FACTORS:
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Missouri rate case (a) $(.12) International growth (d) $.17
Depressed natural gas liquids Regulated Businesses (e) .35
prices and production (b) (.23) Aquila term business (f) .05
Mild weather (c) (.12) Corporate and other .02
- --------------------------------------------------------------------------------
TOTAL NEGATIVE FACTORS $(.47) TOTAL POSITIVE FACTORS $.59
- --------------------------------------------------------------------------------
NET CHANGE FROM 1997 $.12
- --------------------------------------------------------------------------------
</TABLE>
(a) In April 1998, we were ordered by the Missouri Public Service Commission
to reduce rates by $22.7 million annually, or $16.3 million prorated in
1998.
(b) Natural gas liquids prices and production declined 26% and 32%,
respectively.
(c) Winter temperatures as measured by heating degree-days were off 15%,
partially offset by warmer summer temperatures.
(d) Our International growth came from New Zealand and the United Kingdom.
(e) Off-system volume growth, customer additions and the weather recovery plan
were all contributors.
(f) Aquila's term business came on strong, signing over 700 transactions in
1998.
NON-RECURRING ITEMS
Our normalized earnings before interest and taxes (EBIT) for the three
years ended December 31, 1998 were affected by several items that we expect will
not have a continuing impact on UtiliCorp's financial position or results from
operations. The table below summarizes the effect of non-recurring items on
EBIT.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
In millions 1998 1997 1996
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EBIT, as reported $351.4 $359.1 $326.2
Non-recurring items:
Merger termination fee (a) -- (53.0) --
Write-off of deferred merger costs, net (a) -- -- 11.0
Gain on sales lease of a power project (b) -- -- (20.9)
Provision for asset impairments (c) 27.7 26.5 --
United Kingdom gas contract settlements and other reserves (d) 13.4 6.5 --
Australia initial public offering (e) (45.3) -- --
- ----------------------------------------------------------------------------------------------------
Normalized EBIT $347.2 $339.1 $316.3
- ----------------------------------------------------------------------------------------------------
</TABLE>
(a) In 1997, we received $53.0 million from Kansas City Power & Light Company
as a merger termination fee. In 1996, we expensed all previously deferred
merger costs and recorded an $11.0 million charge against earnings.
(b) In 1996, we recorded a gain from a sales lease on a power project. The
gain was partially offset by certain restructuring reserves related to
changes in power project agreements. The result of these items increased
EBIT $20.9 million.
(c) In 1998, we recorded a $27.7 million provision for impaired assets
relating to certain retail gas marketing assets, termination of EnergyOne
L.L.C., and the write-off of an independent power project. In 1997, we
recorded a provision for impaired assets of $26.5 million related to
certain technology and royalty assets.
(d) In 1998, we settled two above-market gas contracts at a net loss of $6.6
million. In addition, a judgement against us on a disputed gas supply
contract requires us to record $6.8 million in interest related to the
contract. In 1997, we recorded a $6.5 million reserve primarily for
unfavorable gas supply contracts in the United Kingdom.
(e) In 1998, United Energy Limited (UEL) sold 42% of its common stock to the
public in Australia. UtiliCorp recorded a $45.3 million gain from the
sale.
We use the term "normalized EBIT" to describe our recurring earnings
before interest and taxes excluding non- recurring items. The term is not meant
to replace actual EBIT or other performance measures used under generally
accepted accounting principles.
28
<PAGE>
REGULATED BUSINESSES
The following table summarizes the domestic Regulated Businesses for the three
years ended December 31, 1998.
THREE-YEAR REVIEW--REGULATED BUSINESSES
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
Dollars in millions 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Sales:
Electric $616.6 $557.4 $519.3
Gas 622.5 767.4 727.9
Other 233.7 258.7 124.8
- -----------------------------------------------------------------------------------------------
Total sales 1,472.8 1,583.5 1,372.0
- -----------------------------------------------------------------------------------------------
Cost of sales:
Electric 235.0 199.1 179.1
Gas 365.4 493.2 455.2
Other 199.1 223.0 84.5
- -----------------------------------------------------------------------------------------------
Total cost of sales 799.5 915.3 718.8
Gross profit 673.3 668.2 653.2
- -----------------------------------------------------------------------------------------------
Operating expenses:
Other operating 256.6 282.4 275.9
Maintenance 49.0 47.7 40.6
Taxes, other than income taxes 54.0 61.2 57.5
Depreciation and amortization 109.1 85.0 83.2
Provision for asset impairments 2.5 -- --
- -----------------------------------------------------------------------------------------------
Total operating expenses 471.2 476.3 457.2
- -----------------------------------------------------------------------------------------------
Income from operations 202.1 191.9 196.0
Other income 5.6 5.6 10.3
- -----------------------------------------------------------------------------------------------
Earnings before interest and taxes (EBIT) 207.7 197.5 206.3
- -----------------------------------------------------------------------------------------------
Non-recurring items:
Provision for asset impairments 2.5 -- --
- -----------------------------------------------------------------------------------------------
Normalized EBIT $210.2 $197.5 $206.3
- -----------------------------------------------------------------------------------------------
Normalized EBIT contribution to UtiliCorp 60.5% 58.2% 65.2%
- -----------------------------------------------------------------------------------------------
Identifiable assets $2,040.9 $2,101.9 $2,061.0
Electric sales and transportation (MWH 000's) 12,443 11,201 9,607
Gas sales and transportation (MCF 000's) 250,010 287,396 301,513
- -----------------------------------------------------------------------------------------------
Electric customers 373,000 365,000 359,000
Gas customers 852,000 829,000 813,000
Appliance service customers 171,000 170,000 169,000
- -----------------------------------------------------------------------------------------------
Total customers 1,396,000 1,364,000 1,341,000
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
ELECTRIC SALES AND TRANSPORTAION
<S> <C>
98............................................ 12,443
97............................................ 11,201
96............................................ 9,607
0 3,000 6,000 9,000 12,000
- -----------------------------------------------------
MWH 000s
</TABLE>
Electric volumes increased due to additional customers and higher volumes sold
outside our network area.
<TABLE>
<CAPTION>
COST OF POWER GENERATED
<S> <C>
UTILICORP..................................... 14.96
COMPETTITORS.................................. 17.78
0 0 5 10 15
- -----------------------------------------------------
DOLLARS PER MWH
</TABLE>
Our cost to generate power at our larger baseload plants (coal-fired plants with
over 150 MW capacity) is 16% lower than costs at similar plants in the area
owned by others.
<TABLE>
<CAPTION>
GAS SALES AND TRANSPORTATION
<S> <C>
98............................................ 250,010
97............................................ 287,396
96............................................ 301,513
0 100,000 200,000 300,000
- -----------------------------------------------------
MCF 000s
</TABLE>
Gas volumes decreased 17% since 1996 due to warmer weather and lower demand for
transportation services.
29
<PAGE>
[PHOTO] [PHOTO]
As Senior Vice President, Energy Heading up Aquila Energy's new
Delivery, Jim Miller oversees leadership team are Chuck Dempster
UtiliCorp's electric and natural gas (left), Chairman and Chief Executive
utility operations, which serve 1.2 Officer, and Ed Mills, President and
million customers in eight states. Chief Operating Officer.
GROSS PROFIT
Gross profit from Regulated Businesses in 1998 was $5.1 million more than in
1997. This is due to a 2.6% increase in utility customers, higher customer usage
and energy sales that together increased gross profit by $29.2 million.
Partially offsetting this increase were the impact of mild weather, which
reduced gross profit by $16.6 million, and the effects of a rate reduction in
Missouri. The rate reduction became effective in April and reduced gross profit
by $12.0 million. The Missouri rate order also increased depreciation expense by
$4.3 million. Winter weather in 1998 was 15% warmer than normal.
Gross profit in 1997 increased $15.0 million compared to 1996. This was
primarily due to customer growth and normal weather in 1997. In 1996, winter
weather was 8% warmer than normal.
OPERATING EXPENSES
Operating expenses decreased $5.1 million in 1998 compared to 1997. To recover
from the effects of mild winter weather in the first quarter, we began a cost
reduction program that reduced expenses by $15.7 million. This savings was
partially offset by higher transmission fees and payroll and benefit increases.
Operating expenses increased $19.1 million in 1997 compared to 1996. This
reflects inflation, greater allocation of expenses from Corporate, and increases
in property taxes and depreciation from utility plant additions.
<TABLE>
<CAPTION>
SALES: REGULATED BUSINESS--ELECTRIC
<S> <C>
98............................................ 616.6
97............................................ 557.4
96............................................ 519.3
0 200 400 600
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
In spite of mild weather and the Missouri electric rate decrease, Regulated
Businesses increased its sales by 11% due to higher volumes sold outside its
network area.
<TABLE>
<CAPTION>
SALES: REGULATED BUSINESS--GAS
<S> <C>
98............................................ 622.5
97............................................ 767.4
96............................................ 727.9
0 200 400 600
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
The mild weather hurt gas sales during the first and fourth quarters of 1998,
causing a sharp decrease in sales for the year.
<TABLE>
<CAPTION>
EBIT (NORMALIZED): REGULATED BUSINESSES
<S> <C>
98............................................ 210.2
97............................................ 197.5
96............................................ 206.3
0 50 100 150 200
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Normalized EBIT increased $12.7 million in 1998 due to strong growth in the
number of customers and reduced expenses.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES: REGULATED BUSINESSES
<S> <C>
98............................................ 101.8
97............................................ 116.6
96............................................ 112.8
0 25 50 75 100
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Capital expenditures are made primarily to expand the system to serve a growing
number of customers, and for maintenance.
30
<PAGE>
AQUILA ENERGY
THREE-YEAR REVIEW--AQUILA ENERGY
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
Dollars in millions 1998 1997 1996
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SALES:
Energy marketing $ 9,692.7 $ 6,017.1 $ 1,882.4
Aquila Gas Pipeline 892.9 1,013.9 790.3
- ------------------------------------------------------------------------------------------------------
TOTAL SALES 10,585.6 7,031.0 2,672.7
- ------------------------------------------------------------------------------------------------------
COST OF SALES:
Cost of energy marketing 9,569.3 5,909.0 1,822.6
Aquila Gas Pipeline 811.9 894.6 664.1
- ------------------------------------------------------------------------------------------------------
Total cost of sales 10,381.2 6,803.6 2,486.7
- ------------------------------------------------------------------------------------------------------
Gross profit 204.4 227.4 186.0
- ------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Operating and maintenance 132.1 121.0 107.7
Depreciation, depletion and amortization 27.7 27.6 28.6
Provision for asset impairments 17.2 15.5 --
- ------------------------------------------------------------------------------------------------------
Total operating expenses 177.0 164.1 136.3
- ------------------------------------------------------------------------------------------------------
Income from operations 27.4 63.3 49.7
Equity earnings in subsidiaries and partnerships 34.5 30.5 48.6
Minority interest expense and other 7.8 11.4 8.1
- ------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INTEREST AND TAXES (EBIT) 54.1 82.4 90.2
- ------------------------------------------------------------------------------------------------------
NON-RECURRING ITEMS:
Provision for asset impairments 17.2 15.5 --
Gain on sales lease of power project -- -- (20.9)
- ------------------------------------------------------------------------------------------------------
NORMALIZED EBIT $ 71.3 $ 97.9 $ 69.3
- ------------------------------------------------------------------------------------------------------
NORMALIZED EBIT CONTRIBUTION TO UTILICORP 20.5% 28.9% 21.9%
- ------------------------------------------------------------------------------------------------------
EBIT BY BUSINESS SUBUNIT:
Energy marketing $ 20.5 $ 18.4 $ (4.2)
Aquila Gas Pipeline 18.6 51.8 51.4
Independent power projects 32.2 27.7 22.1
- ------------------------------------------------------------------------------------------------------
TOTAL AQUILA ENERGY EBIT $ 71.3 $ 97.9 $ 69.3
- ------------------------------------------------------------------------------------------------------
Identifiable assets $ 2,290.9 $ 2,275.5 $ 1,900.1
Physical gas volumes marketed (billion cubic feet per day) 9.6 6.8 3.5
Gas throughput volumes(million cubic feet per day) 475 483 493
Natural gas liquids--price per gallon $ .25 $ .34 $ .35
Natural gas liquids produced (thousand barrels per day) 25 37 41
Electricity marketing volumes (MWH 000's) 121,194 65,258 6,495
- ------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
SALES: AQUILA ENERGY
<S> <C>
98............................................ 10,585.6
97............................................ 7,031.0
96............................................ 2,672.7
0 2,000 4,000 6,000 8,000 10,000
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Annual sales have increased nearly 300% since 1996. This is due to rapid growth
in volumes and execution of our energy merchant strategy.
<TABLE>
<CAPTION>
EBIT (NORMALIZED): AQUILA ENERGY
<S> <C>
98............................................... 71.3
97............................................... 97.9
96............................................... 69.3
0 20 40 60 80
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Normalized EBIT declined in 1998 due to a 26% decrease in prices for natural gas
liquids (NGLs) and a 32% decrease in NGL volumes compared to 1997.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES: AQUILA ENERGY
<S> <C>
98............................................... 33.8
97............................................... 28.4
96............................................... 26.4
0 5 10 15 20 25 30
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Capital expenditures primarily relate to line extensions for new well
connections on the Aquila Gas Pipeline gathering system.
31
<PAGE>
GROSS PROFIT
Gross profit in 1998 declined $23.0 million compared to 1997. The decrease
reflects a $38.3 million drop in gross profit from Aquila Gas Pipeline (AQP)
that was partially offset by a $15.3 million increase from Energy Marketing.
AQP's results in 1998 were lower due to a 26% decrease in NGL prices and a 32%
decrease in NGL production. This combination reduced AQP's 1998 gross profit by
$25 million. NGL prices are closely tied to crude oil prices, which declined
significantly in 1998. As oil prices declined, drilling activity in the Austin
Chalk region of Texas, AQP's main gathering area, was limited to deep gas wells
which produce less liquid. NGL production also declined because AQP voluntarily
bypassed certain volumes due to low prices. The NGL price declines were largely
shared with producers as a majority of AQP's contracts are structured as percent
of production. We do not expect NGL prices or production to improve in 1999.
Gross profit from energy marketing increased 14% in 1998 compared to 1997,
primarily due to the following:
- Increased gross margin from electricity, partially offset by lower gas
marketing margins.
- An 86% increase in electricity marketing volumes as this market
segment continued to expand.
- A 131% increase in gross margin from longer-term contracts (generally
those of more than a year).
- Better results from commercial and industrial segments, achieved by
increased focus on existing operations.
In June 1998, the price of electricity varied widely as the market reacted
to a power shortage caused by several power plant outages and low reserve
margins. During June, electricity prices fluctuated between $30 and $7,500 per
megawatt-hour. This caused many market participants to panic as they covered
open short positions with high-priced electricity. In addition, some firms did
not honor their contract obligations, causing others to replace the lost
electricity with higher-priced supply. We did not incur net losses from June's
unusual pricing patterns. Assessing credit and counterparty risk is a
cornerstone principle of our risk management system of internal control. This is
why our credit policy is administered by a function that is independent from
trading and sales.
Gross profit in 1997 increased $41.4 million or 22% compared to 1996. This
was due to a 94% and 905% increase in gas and electricity marketing volumes
which resulted in $26.2 million and $9.0 million, respectively, in additional
margin. These volumetric increases reflect the impact of an aggressive expansion
program.
Gross profit from AQP decreased $6.9 million in 1997 compared to 1996. NGL
production volumes declined because of leaner gas streams, lower NGL prices and
reduced gas marketing results. In 1997, NGL production volumes were down 10% and
prices were down 3% compared to 1996. The leaner gas streams were due to
generally deeper drilling in the Austin Chalk area.
Gross profit from small commercial and industrial gas marketing increased
$13.1 million in 1997 over 1996 as these businesses were assimilated into Aquila
from another business segment. The increase was due to the expansion of sales to
industrial and commercial customers. In 1996, the retail business had fixed
price sales contracts against variable purchase contracts when the price of
natural gas escalated. Although the retail business improved in 1997, it still
had a net EBIT loss of $5.1 million in 1997 compared to $13.1 million in 1996.
OPERATING EXPENSES
Operating expenses in 1998 were $11.2 million higher than in 1997, after
normalizing for non-recurring items in both periods. Operating expenses
increased primarily as a result of additional staffing needed to support the
growth of the business.
Operating expenses increased $12.3 million in 1997 compared to 1996, after
normalizing for the provision for asset impairment. The increase reflects higher
staffing costs to support Aquila's aggressive growth strategy and rapid increase
in marketing volumes.
EQUITY IN EARNINGS
Equity in earnings increased $4.0 million in 1998 compared to 1997, primarily
because we sold part of our ownership in an independent power project for a $3.6
million gain. Equity in earnings increased $2.8 million in 1997 compared to
1996, after normalizing for the gain on sales lease of $20.9 million. The
increase was primarily due to innovative gas tolling and dispatch arrangements
at one of the independent power projects and increased production from another
project.
<TABLE>
<CAPTION>
NGL PRICES PER GALLON
<S> <C>
98............................................... 25
97............................................... 34
96............................................... 35
0 10 20 30
- -----------------------------------------------------
CENTS
</TABLE>
Prices for natural gas liquids declined by 26% in 1998 compared to 1997. Each
$.01 change in price represents approximately $1.3 million in EBIT. The outlook
for 1999 is no better than 1998.
<TABLE>
<CAPTION>
EBIT FROM LONG-TERM DEALS
<S> <C>
98............................................... 57%
97............................................... 20%
96............................................... 14%*
0 10 20 30 40 50
- -----------------------------------------------------
PERCENT
</TABLE>
As Aquila's energy marketing business has expanded, total margins from longer
term transactions have increased as a percentage of Aquila's total margins.
* Excludes retail EBIT.
32
<PAGE>
INTERNATIONAL
The following table summarizes the company's International operations for the
three years ended December 31, 1998.
THREE-YEAR REVIEW--INTERNATIONAL
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
Dollars in millions 1998 1997 1996
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SALES $ 504.1 $ 305.2 $ 284.4
- ------------------------------------------------------------------------------------------------
COST OF SALES 413.1 246.1 209.7
- ------------------------------------------------------------------------------------------------
Gross profit 91.0 59.1 74.7
- ------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Other operating 40.5 21.6 24.8
Maintenance 4.2 10.0 9.0
Taxes, other than income taxes 12.1 11.3 12.2
Depreciation and amortization 13.0 11.0 12.5
- ------------------------------------------------------------------------------------------------
Total expense 69.8 53.9 58.5
- ------------------------------------------------------------------------------------------------
Income from operations 21.2 5.2 16.2
Equity earnings in subsidiaries and partnerships 88.5 42.3 60.1
Other income (expense) (5.9) 5.0 3.4
- ------------------------------------------------------------------------------------------------
EARNINGS BEFORE INTEREST AND TAXES (EBIT) 103.8 52.5 79.7
- ------------------------------------------------------------------------------------------------
NON-RECURRING ITEMS:
Reserve for United Kingdom gas contracts -- 5.0 --
United Energy initial public offering (45.3) -- --
National Power interest charge 6.8 -- --
Midlands Gas contract settlement 6.6 -- --
- ------------------------------------------------------------------------------------------------
NORMALIZED EBIT $ 71.9 $ 57.5 $ 79.7
- ------------------------------------------------------------------------------------------------
NORMALIZED EBIT CONTRIBUTION TO UTILICORP 20.8% 17.0% 25.2%
- ------------------------------------------------------------------------------------------------
CUSTOMERS:
- ------------------------------------------------------------------------------------------------
Australia 546,000 540,000 530,000
Canada 132,000 131,000 129,000
New Zealand (a) 468,000 282,000 276,000
United Kingdom 1,011,000 97,000 48,000
- ------------------------------------------------------------------------------------------------
TOTAL CUSTOMERS 2,157,000 1,050,000 983,000
- ------------------------------------------------------------------------------------------------
Identifiable assets $ 1,437.0 $ 789.0 $ 848.3
- ------------------------------------------------------------------------------------------------
</TABLE>
(a) Customer count for 1998 includes indirect customers from the TrustPower
transaction that closed in January 1999.
SUMMARY
International normalized EBIT consists of operations and equity investments in
the following countries for the three years ended December 31, 1998.
<TABLE>
<CAPTION>
In millions 1998 1997 1996
- --------------------------------------------------
<S> <C> <C> <C>
Australia $ 22.3 $ 27.0 $ 38.3
Canada 22.0 26.2 27.7
New Zealand 21.4 9.9 11.6
United Kingdom 6.2 (5.6) 2.1
- --------------------------------------------------
TOTAL $ 71.9 $ 57.5 $ 79.7
- --------------------------------------------------
</TABLE>
The normalized EBIT by country is discussed below.
GROSS PROFIT
International gross profit increased $31.9 million in 1998 compared to 1997.
This increase is primarily due to the consolidation of UnitedNetworks, beginning
in October 1998, because of our increased level of ownership. Gross profit from
UnitedNetworks was $23.8 million. Prior to October 1998, our New Zealand
investments were accounted for under the equity method and shown in "Equity
earnings in subsidiaries and partnerships." Gross profit from the United Kingdom
(U.K.) increased $14.8 million in 1998 after adjusting for non-recurring items.
This is due to an increase in trading and transportation margin resulting from
the execution of our wholesale services strategy. Our indirect customers in the
U.K. increased from 97,000 to more than 1 million in 1998. We bought out two
above-market gas supply contracts in 1998 for $25.6 million. The contracts had
hampered profitability in the 1998 first quarter and in 1997. A reserve we set
up in advance covered $19.0 million of this amount.
Gross profit from Canada was down $5.2 million in 1998 compared to 1997 due
to milder winter weather and higher power costs.
33
<PAGE>
United Kingdom gross profit was $7.2 million lower in 1997 compared to
1996, after adjusting for non-recurring items. This mainly reflects two
high-cost gas supply contracts that took effect in October 1996.
OPERATING EXPENSES
Operating expenses increased $15.9 million in 1998 compared to 1997. This was
due to a $15.8 million increase from New Zealand related to the consolidation of
UnitedNetworks in October 1998.
Operating expenses in 1997 were $4.6 million lower than in 1996 due to
higher currency values in most of our foreign markets in 1996 and higher
expatriate expenses in 1996 due to initial relocation costs.
Initial Public Offering--United Energy Limited
In May 1998, United Energy Limited (UEL) sold 42% of its common stock to the
public. As a result, we recorded a $45.3 million gain. Also, our ownership
percentage in UEL reduced from 49.9% to 29%. Concurrent with UEL's stock
offering, we bought an additional 5% in UEL from another company. Prior to the
common stock sale, UEL repaid approximately $101 million in debt notes. The
effect of this transaction reduced our ownership position, but was substantially
offset by higher earnings at UEL as a result of lower interest costs and
application of the $101 million to reduce our debt.
COMPETITION IN AUSTRALIA
The State of Victoria is deregulating its electricity market in stages.
Currently, customers with yearly usage above 160 megawatt-hours (industrial and
large commercial customers) can choose their retail electricity suppliers. After
January 1, 2001, all UEL customers will be able to choose their retail
electricity suppliers. A majority of UEL's gross margin comes from distribution
line charges that would not be affected by this customer choice.
NEW ZEALAND ACQUISITIONS AND DISPOSITIONS
In 1998, through a series of transactions we gained control of Power New Zealand
Limited (PNZ) through the purchase of an additional 48% interest. We bought the
additional 48% for $245 million, bringing our total ownership interest in PNZ to
79%.
As part of New Zealand's Electricity Industry Reform Act of 1998, electric
companies were required to separate the ownership of their lines (distribution)
and supply (generation and retail) businesses and choose to become either a
lines company or a supply company. This requires selling any other piece of the
business not in the chosen segment. PNZ decided to become a lines company and as
a result, it has sold its retail business to TransAlta New Zealand Ltd. In
addition, PNZ bought TransAlta's lines business, paying a net $238 million after
the two transactions. PNZ also acquired a lines business from TrustPower for
$261 million, effective January 1999. As part of the sale of PNZ's retail
business, PNZ sold the Power New Zealand name to TransAlta. Our network business
in New Zealand is now known as UnitedNetworks Limited. We expect that all of
these transactions will increase the EBIT contribution from New Zealand by $55
million in 1999 compared to 1998.
<TABLE>
<CAPTION>
SALES: INTERNATIONAL
<S> <C>
98............................................... 504.1
97............................................... 305.2
96............................................... 284.4
0 100 200 300 400 500
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Sales in 1998 increased 65% over 1997 due to a sharp increase in customers in
the U.K. and increased ownership in our New Zealand businesses.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES: INTERNATIONAL
<S> <C>
98............................................... 20.0
97............................................... 19.4
96............................................... 21.5
0 5 10 15 20
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Capital expenditures primarily relate to the expansion of our Canadian electric
system and construction of a gas storage facility in the U.K.
<TABLE>
<CAPTION>
EBIT (NORMALIZED): INTERNATIONAL
<S> <C>
98............................................... 71.9
97............................................... 57.5
96............................................... 79.7
0 20 40 60
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Normalized EBIT increased by $14.4 million in 1998 due to strong growth in the
U.K. and New Zealand as we executed our growth initiatives.
34
<PAGE>
CORPORATE MATTERS
CORPORATE AND OTHER
The table below summarizes the corporate and other EBIT for the three years
ended December 31, 1998. Corporate primarily contains the retained costs of the
company that are not allocated to the business units and the net losses from the
company's investment in EnergyOne, L.L.C.
<TABLE>
<CAPTION>
In millions 1998 1997 1996
- ------------------------------------------------------------
<S> <C> <C> <C>
EBIT, as reported $ (14.2) $ 26.6 $ (50.0)
- ------------------------------------------------------------
Merger termination -- (53.0) 11.0
Asset impairment provision 8.0 11.0 --
Other -- 1.6 --
- ------------------------------------------------------------
Normalized EBIT $ (6.2) $ (13.8) $ (39.0)
- ------------------------------------------------------------
</TABLE>
Corporate and other normalized EBIT increased by $7.6 million due to the
elimination of losses from our EnergyOne partnership with PECO Energy Company.
The partnership was terminated in April 1998. Corporate and other normalized
EBIT improved by $25.2 million in 1997 compared to 1996 due to the elimination
of certain corporate activities and transfer of capital costs associated with
new information systems recorded at corporate, but allocated to business units.
COMPETITION
DOMESTIC UTILITY OPERATIONS. Our domestic utility businesses operate
in a regulated environment despite various legislative efforts at the federal
level. Industrial and large commercial customers largely have access to energy
sources so some of the competitive pricing benefits have been transferred to
these customers through open access tariffs relating to transmission lines and
pipelines. Without federal legislation, competition at the retail level cannot
form since the rules will be different in each state. As a result of our
assessment of retail competition possibilities, we reduced most retail
activities until the market more fully develops.
ACCOUNTING IMPLICATIONS. We currently record the economic effects of regulation
in accordance with the provisions of Statement of Financial Accounting Standards
No. 71 (SFAS No. 71), "Accounting for the Effects of Certain Types of
Regulation," and accordingly our balance sheet reflects certain costs as
regulatory assets. We expect that our rates will continue to be based on
historical costs for the foreseeable future. If we discontinued applying SFAS
No. 71, we would make adjustments to the carrying value of our regulatory
assets. Total net regulatory assets at December 31, 1998 were $96.5 million.
ENERGY MARKETING. Our energy marketing businesses operate in a fully competitive
environment that rewards participants on price, service and execution. Our
energy marketing businesses compete for customers with some of the largest
utility and energy companies in North America. The industry is premised on large
volume sales with relatively low margins. Companies that operate in this
industry must fully understand the price sensitivity and volatility of
commodities. The public became more aware of some of the risks associated with
this industry when a number of companies announced sudden losses resulting from
the June price spike in electricity. We expect price volatility and we expect
events like the June price spike to recur.
ENVIRONMENTAL MATTERS
We have been named a potentially responsible party (PRP) at three PCB disposal
facilities. Our combined cleanup expenditures have been less than $1 million to
date. We anticipate that future expenditures on these sites will not be
significant.
We also own or once operated 29 former manufactured gas plants which may
require some form of environmental remediation. See Note 15 to the Consolidated
Financial Statements for further discussion of this topic.
In December 1996, the EPA published its final rule for nitrous oxide (NOx)
emissions under the requirements of the Clean Air Act Amendments of 1990. The
new NOx regulations will affect one of our power plants by requiring us to
install additional emissions controls by January 1, 2000. In October 1998, the
EPA published new air quality standards to further reduce the emission of NOx.
These more strict standards will require us to install new equipment on our
baseload coal units in Missouri that we estimate will cost $35 million. The
ultimate cost is under debate and subject to change. The new standards as
written are effective in May 2003.
YEAR 2000 ISSUES
Our computer systems as presently configured may not recognize the two-digit
date of "00" as the year 2000. This could cause systems to shut down or
malfunction. In order to address potential year 2000 issues, we established a
Year 2000 Project Office to coordinate efforts in our operating units to ensure
that computer systems and applications will function properly beyond 1999.
Many of our information systems and related software are already year
2000-ready. We have installed a major new software system that includes
financial, customer information (in certain locations) and support systems. We
also expect to have our new customer information system fully installed by
mid-1999. We expect these projects, known internally as "Project BTU," to
replace at least 80% of potentially affected software. We began Project BTU in
1995 to update our internal support systems and position us to serve our
customers better. Total expenditures for the new systems will be approximately
$186.0 million. Of this amount, to date we have spent $143.9 million.
We are also coordinating the identification and testing of remaining software,
information technology devices, embedded technology systems, and services
provided by third parties that may be affected by the year 2000. We completed
the identification and testing phases in 1998 and will begin remediation in
1999. At this time, we do not have a contingency plan to address unforeseen
issues, but we expect the Project Office to have one by mid-1999. We are
currently preparing budgets and estimates of
35
<PAGE>
remediation costs for this portion of our year 2000 remediation of
mission-critical systems. We expect the remediation of certain
non-mission-critical systems to extend beyond 1999. We expect to spend
approximately $2.3 million in total remediation costs outside of Project BTU.
We are evaluating the impact of internal and external year 2000 issues on
our operations to develop a model on which to base contingency planning. We are
conducting internal evaluations and discussions with other utilities, as well as
participating in industry-wide efforts being conducted by the North American
Electric Reliability Council and the Gas Industry Standards Board, to prepare
for this issue and ensure the company's efforts are in line with the rest of the
industry.
For complete system changeouts, we capitalize cost under guidelines
described in Emerging Issues Task Force (EITF) 97-13, "Accounting for Costs
Incurred in Connection with a Consulting Contract or an Internal Project that
Combines Business Process Reengineering and Information Technology
Transformation." For programming fixes on existing systems, we record these
costs as maintenance expense.
MARKET RISK--TRADING
We are exposed to market risk, including changes in commodity prices,
interest rates and currency exchange rates. To manage the volatility relating to
these exposures, we enter into various derivative transactions in accordance
with our policy approved by the Board of Directors. We routinely enter into
financial instrument contracts to position the portfolio. Our trading portfolios
consist of physical and financial natural gas, electricity, coal and interest
rate contracts. These contracts take many forms including futures, forwards,
swaps and options.
We measure the risk in our trading portfolio using value-at-risk
methodologies, to simulate forward price curves in the energy markets and
estimate the size of future potential losses. The quantification of market risk
using value-at-risk methodologies provides a consistent measure of risk across
diverse energy markets and products. The use of this method requires a number of
key assumptions, such as:
- Selection of a confidence level (we use 95%).
- Estimated holding period (we use three days).
- Use of historical estimates of volatility and correlation with recent
activity more heavily weighted.
At December 31, 1998, our value at risk was:
<TABLE>
<CAPTION>
In millions
- ------------------------------------
<S> <C>
Electricity $ .7
Natural gas 2.2
- ------------------------------------
</TABLE>
The average value at risk for all commodities during 1998 was $3.8 million.
We also use additional risk control mechanisms such as stress testing,
daily loss limits and commodity position limits, as well as daily monitoring of
the trading activities by an independent function.
Although interest and foreign currency risks are monitored within the
commodity portfolios and value-at-risk calculation, separate portfolios for
interest and foreign currency risks do not exist. The value of our commodity
portfolios are impacted by interest rates as the portfolio is valued using an
estimated interest discount factor to December 31, 1998. We often sell Canadian
sourced natural gas into the U.S. markets accepting U.S. dollars from customers,
but paying Canadian dollars to suppliers. This exposes our portfolio to currency
risk. We currently do not hedge this exposure.
The table below shows the expected cash flows associated with the interest
rate financial instruments at December 31, 1998.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Dollars in millions 1999 2000 2001 2002 2003 Thereafter Total
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Variable to fixed rate $ 1.6 -- -- -- -- -- $ 1.6
Average rate paid 5.28% -- -- -- -- --
Average rate received 5.36% -- -- -- -- --
Fixed to variable rate -- -- $(3.6) -- $(1.2) $(1.1) $(5.9)
Average rate paid -- -- 7.36% -- 6.80% 6.71%
Average rate received -- -- 3.81% -- 4.46% 5.64%
</TABLE>
MARKET RISK--NON-TRADING
We are also exposed to commodity price changes outside of price risk
management activities. The following table summarizes these exposures on an EBIT
basis.
<TABLE>
<CAPTION>
Commodity EBIT
Price Change Impact (a)
- ----------------------------------------------------------
<S> <C> <C>
NGL price per gallon +/- $.01 $1.3 million
Natural gas price per MCF +/- $.10 .3 million
United Kingdom natural
gas prices +/- $.01 1.3 million
- ----------------------------------------------------------
</TABLE>
(a) Assumes the price change occurs for an entire year. For the U.K., the price
change assumes that it occurs over the entire forward contract period.
CURRENCY RATE EXPOSURE
We do not currently hedge our net investment in foreign operations. As a
result, the foreign denominated assets and liabilities fluctuate in value.
Historically, our net exposure to changes in foreign currency has been limited
as the company's foreign investments were financed through foreign debt.
36
<PAGE>
The table below summarizes the average value of foreign currencies used to
value sales and expenses along with the related sensitivity.
<TABLE>
<CAPTION>
EBIT Impact Unit Value in U.S. Dollars
of 10% change (a) --------------------------
1998 1997 1996
- ---------------------------------------------------------------------
<S> <C> <C> <C> <C>
Australian dollar + $2.2 million $ .63 $ .74 $ .78
Canadian dollar + 2.2 million .67 .72 .73
New Zealand dollar + 2.1 million .54 .66 .69
British pound + .6 million 1.66 1.65 1.53
- ---------------------------------------------------------------------
Total + $7.1 million
- ---------------------------------------------------------------------
</TABLE>
(a) Assuming a 10% change in local currency value relative to the U.S. dollar
if the change occurred uniformly over the entire year, based on 1998
financial results.
INTEREST RATE EXPOSURE
We have approximately $446.5 million of variable rate debt as of December
31, 1998. A 100-basis-point change in each debt's benchmark rate would affect
net income by approximately $2.7 million. We hedged approximately $316 million
of variable debt with fixed rate financial instruments.
LIQUIDITY AND CAPITAL RESOURCES
Our cash requirements arise primarily from continued growth, electric and
gas utility construction programs, non-regulated investment opportunities and
Aquila Energy's working capital requirements. Our ability to attract the
necessary financial capital at reasonable terms is critical to our overall plan.
Historically, we have financed acquisitions and investments initially with
short-term debt and subsequently funded them with an appropriate mix of common
equity and long-term debt securities, depending on prevailing market conditions.
A primary source of short-term cash has been bank loans which aggregated
$235.6 million, $113.8 million and $202.0 million at December 31, 1998, 1997 and
1996, respectively. We can also issue up to $150 million of commercial paper
supported by a $250 million committed revolving credit agreement. The credit
agreement expires in December 2000 and allows for the issuance of notes at
interest rates based on various money market rates. We had no commercial paper
borrowings at December 31, 1998 and 1997.
To maintain flexibility in our capital structure and to take advantage of
favorable short-term rates, we sell our accounts receivable under two programs
to fund a portion of our short-term cash requirements. The level of funding
available from these programs is limited to $280 million and the amount
fluctuates seasonally. We had sold approximately $248 million under these
programs at December 31, 1998. These programs were fully utilized at December
31, 1997 and 1996.
In 1998, certain customers prepaid $185.2 million for future gas supplies.
We used this cash to reduce short-term debt. In the future we will incur
short-term debt to buy gas over the contract period.
In 1998 we sold 12.98 million shares of our common stock at $23.41 per
share, net of underwriting costs. The $304 million in net proceeds was used to
reduce domestic short-term debt and accounts receivable sales programs. Our
capital structure consisted of the following components at December 31, 1998 and
1997.
<TABLE>
<CAPTION>
1998 1997
- ---------------------------------------------------
<S> <C> <C>
Common stock equity 42.5% 40.3%
Monthly income preferred stocks 2.9 3.5
Short-term debt 6.9 3.9
Long-term debt 47.7 52.3
- ---------------------------------------------------
Total Capitalization 100.0% 100.0%
- ---------------------------------------------------
</TABLE>
We have approximately 2.2 million treasury shares as of December 31, 1998,
that we expect to issue to our stock plans in 1999. Our dividend payout ratio
was 73% in 1998 (annualized dividends of $1.20 divided by basic EPS of $1.65).
We expect our EPS growth to be approximately four times our dividend growth.
This should reduce our payout ratio to about 50-60% over the next five years.
The combination of higher earnings growth compared to dividends and the expected
reissue of treasury stock will increase the equity component in our capital
structure in the future.
37
<PAGE>
CASH REQUIREMENTS
Future cash requirements include utility plant additions, required redemptions
of long-term securities, and acquisition opportunities. We estimate expenditures
over the next three years for these activities, excluding acquisitions, will be
as follows:
<TABLE>
<CAPTION>
Actual Future Cash Requirements
------ ------------------------
In millions 1998 1999 2000 2001
- ---------------------------------------------------------------
<S> <C> <C> <C> <C>
Regulated Businesses $101.8 $118.0 $113.0 $115.0
Aquila Energy 33.8 25.0 130.0 161.0
International 20.0 32.0 31.0 27.0
Maturing long-term debt 216.4 248.8 164.5 44.4
Other 48.7 55.0 42.0 23.0
- ---------------------------------------------------------------
Total $420.7 $478.8 $480.5 $370.4
- ---------------------------------------------------------------
</TABLE>
Aquila Energy plans to build a 500-megawatt combined cycle generation
plant, initially to serve the capacity needs of our Regulated Businesses
beginning in June 2001. The new plant is expected to cost approximately $241
million.
We expect to refinance our maturing debt issues in 1999 and will consider
refinancing or restructuring certain higher coupon debt in 1999 if market
conditions warrant. We believe that our available cash resources from both
operating cash flows and borrowing capacity will be adequate to meet our
anticipated future cash requirements.
SIGNIFICANT BALANCE SHEET MOVEMENTS
Total assets increased $878 million in 1998 compared to 1997. This increase is
primarily due to the following:
- We invested approximately $609.7 million in New Zealand in 1998 to
obtain control of UnitedNetworks, at the time transitioning to become
a lines business, and to acquire an additional lines business. The
increase also reflects the buyout of a partner in Australia.
- Assets of the company reflect UnitedNetworks on a consolidated basis
for 1998, versus as an equity investment in 1997.
- We purchased 47 Bcf of gas held in storage at December 31, 1998 that
will be used in Aquila's gas marketing business.
- Price risk management assets (current and long-term) increased $105.6
million, reflecting the expansion of Aquila's business in 1998.
Total liabilities increased in 1998 by $595.3 million and common
shareowners' equity increased by $282.7 million in 1998 due to the following:
- Long-term debt increased by $116.4 million in 1998 due primarily to
the acquisition activity in New Zealand, partially offset by maturing
debt and the application of $101 million against debt that we received
from UEL.
- Short-term debt increased $121.8 million in 1998 due to the
acquisition activity in New Zealand.
- Minority interests increased by $92.6 million in 1998 due to New
Zealand acquisition activity.
- Price risk management liabilities increased $206.4 million, reflecting
the expansion of Aquila's business in 1998.
- Common shareowners' equity increased by $282.7 million due to the sale
of 12.98 million common shares, partially offset by treasury shares
held.
AQUILA GAS PIPELINE BUYOUT PROPOSAL
In November 1998, we made a proposal to acquire the 18% of AQP's common stock we
do not already own for $8.00 per share. An independent committee of AQP'S Board
of Directors is evaluating the proposal.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133 established accounting and
reporting standards for derivative instruments and hedging activities requiring
that every derivative instrument, including certain derivative instruments
embedded in other contracts, be recorded in the balance sheet as either an asset
or liability measured at its fair value. The Statement requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that the company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS 133 must be adopted for fiscal years beginning after
June 15, 1999.
SFAS 133 will impact our hedging activities at Aquila Energy and Aquila Gas
Pipeline, corporate treasury activities, foreign subsidiary trading activities,
and power trading contracts. We have not quantified this impact.
In 1998 the Emerging Issues Task Force (EITF) agreed to require companies
to mark to market their energy trading activities beginning in 1999. We already
use the mark-to-market method of accounting for domestic trading activities.
However, we engage in certain trading activities internationally for which we do
not use mark-to-market accounting. We are evaluating the impact this will have
on our financial results. At this time we cannot estimate that impact.
38
<PAGE>
WE'VE GOT LIFE'S LITTLE
EMERGENCIES COVERED.
[GRAPHIC]
Appliances
Plumbing & Electrical
Heating & Cooling
For more information call 888-4-Blondie
www.serviceone.com
A UtiliCorp United Company
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 operations or acquisition
activity.
FORWARD-LOOKING INFORMATION
This report contains forward-looking information. Such statements involve risks
and uncertainties and there are certain important factors that could cause
actual results to differ materially from those anticipated. Some of the
important factors which could cause actual results to differ materially from
those anticipated include:
- Weather, which can affect results significantly to the extent that
temperatures differ from normal. Both our utility and energy merchant
businesses are weather-sensitive.
- The timing and extent of changes in energy commodity prices and
interest rates.
- The pace and degree of regulatory changes in the U.S. and abroad.
- NGL prices and volumes, which are particularly volatile and difficult
to predict.
- The pace of well connections to our gathering system.
- The value of the U.S. dollar relative to the British pound, Canadian
dollar, Australian dollar and New Zealand dollar.
- The continued expansion of the electric power markets and development
of liquid term markets.
- Pending rate proceedings.
<TABLE>
<CAPTION>
CASH FROM OPERATIONS
<S> <C>
98............................................ 276.8
97............................................ 349.0
96............................................ 262.8
0 100 200 300
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Cash from operations funds our normal capital expenditures and our dividend
requirements.
<TABLE>
<CAPTION>
UTILITY PLANT ADDITIONS
<S> <C>
98............................................ 121.8
97............................................ 133.2
96............................................ 134.3
0 25 50 75 100 125
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
Total utility plant additions have remained relatively constant since 1996. Our
capital expenditures have been made to serve new customers and to replace
utility plant.
A UtiliCorp United Company
39
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
In millions except per share 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SALES $ 12,563.4 $ 8,926.3 $ 4,332.3
Cost of sales 11,596.0 7,972.0 3,420.3
- -----------------------------------------------------------------------------------------------------------------
GROSS PROFIT 967.4 954.3 912.0
- -----------------------------------------------------------------------------------------------------------------
Operating, administrative and maintenance expense 548.9 554.9 549.8
Depreciation, depletion, and amortization 150.0 129.6 125.4
Provision for asset impairments 27.7 26.5 --
Write-off of deferred merger costs, net of termination fee received -- -- 11.0
- -----------------------------------------------------------------------------------------------------------------
INCOME FROM OPERATIONS 240.8 243.3 225.8
- -----------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE):
Equity in earnings of investments and partnerships 125.1 68.8 108.7
Minority interests (5.6) (6.5) (8.0)
Merger termination fee -- 53.0 --
Other income (expense) (8.9) .5 (.3)
- -----------------------------------------------------------------------------------------------------------------
TOTAL OTHER INCOME 110.6 115.8 100.4
- -----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INTEREST AND TAXES 351.4 359.1 326.2
- -----------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE:
Interest expense long-term debt 111.4 115.5 118.0
Interest expense short-term debt 12.3 10.9 12.8
Minority interest in income of partnership 8.9 8.9 8.9
- -----------------------------------------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE 132.6 135.3 139.7
- -----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES 218.8 223.8 186.5
Income taxes 86.6 89.7 80.7
- -----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF SOFTWARE ACCOUNTING CHANGE 132.2 134.1 105.8
- -----------------------------------------------------------------------------------------------------------------
Loss on retirement of debt (net of income tax of $4.5) -- 7.2 --
Cumulative effect of software accounting
change (net of income tax of $3.2) -- 4.8 --
- -----------------------------------------------------------------------------------------------------------------
Net income 132.2 122.1 105.8
Preference dividends -- .3 2.1
- -----------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON SHARES $ 132.2 $ 121.8 $ 103.7
- -----------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic 80.07 80.42 70.81
Diluted 81.18 81.00 71.29
- -----------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE:
Basic $ 1.65 $ 1.51 $ 1.46
Diluted 1.63 1.51 1.46
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
ALL SHARE AND PER SHARE AMOUNTS HAVE BEEN RESTATED FOR THE 3-FOR-2 STOCK SPLIT.
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
[GRAPHIC]
<TABLE>
<CAPTION>
SALES GROWTH -- AQUILA AND TOTAL
<S> <C>
Aguila..................................... 10.6
98 Total...................................... 12.6
Aguila..................................... 7.0
97 Total...................................... 8.9
Aguila..................................... 2.7
96 Total...................................... 4.3
0 4 8 12
- ---------------------------------------------------
DOLLARS IN BILLIONS
</TABLE>
Annual sales have increased by $8.3 billion or 190% since 1996, primarily due to
rapid growth at Aquila Energy.
40
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------
Dollars in millions 1998 1997
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 120.5 $ 89.5
Funds on deposit 13.4 31.5
Accounts receivable, net 1,137.5 1,165.1
Inventories and supplies 235.1 111.6
Price risk management assets 173.1 121.5
Prepayments and other 85.8 95.2
- -----------------------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS 1,765.4 1,614.4
- -----------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 3,313.9 2,480.3
Investments in subsidiaries and partnerships 519.8 691.2
Price risk management assets 215.5 161.5
Deferred charges 176.9 166.1
- -----------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 5,991.5 $ 5,113.5
- -----------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREOWNERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 248.8 $ 149.6
Short-term debt 235.6 113.8
Accounts payable 1,275.9 1,356.3
Accrued liabilities 50.6 13.8
Price risk management liabilities 192.2 123.7
Other 89.6 52.7
- -----------------------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 2,092.7 1,809.9
- -----------------------------------------------------------------------------------------------------------
LONG-TERM LIABILITIES:
Long-term debt, net 1,375.8 1,358.6
Deferred income taxes and credits 429.5 362.7
Price risk management liabilities 308.4 170.5
Minority interests 151.6 59.0
Other deferred credits 87.2 89.2
- -----------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM LIABILITIES 2,352.5 2,040.0
- -----------------------------------------------------------------------------------------------------------
Company-obligated mandatorily redeemable
preferred securities of partnership 100.0 100.0
Common shareowners' equity 1,446.3 1,163.6
Commitments and contingencies
- -----------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREOWNERS' EQUITY $ 5,991.5 $ 5,113.5
- -----------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<TABLE>
<CAPTION>
FOREIGN ASSETS AT YEAR END
<S> <C>
98........................................... 1,655.0
97........................................... 907.9
96........................................... 940.9
95........................................... 712.1
94........................................... 295.4
0 500 1,000 1,500
- -----------------------------------------------------
DOLLARS IN MILLIONS
</TABLE>
International asset growth in 1998 primarily reflects acquisitions in New
Zealand. We invested an additional $261 million there in January 1999.
<TABLE>
<CAPTION>
EQUITY RATIO
<S> <C>
98........................................... 42.5%
97........................................... 40.3%
96........................................... 38.2%
0 10 20 30 40
- -----------------------------------------------------
PERCENT
</TABLE>
Our equity ratio improved in 1998 due to the common stock offering in December
1998. We expect our equity ratio to be about 40% in 1999.
41
<PAGE>
CONSOLIDATED STATEMENTS OF COMMON SHAREOWNER'S EQUITY
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------
Dollars in millions except per share 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
COMMON STOCK: authorized 200,000,000 shares, par value $1 per
share, 93,574,853 shares outstanding (80,630,700 at December 31,
1997 and 79,940,468 at December 31, 1996); authorized 20,000,000
shares of Class A common stock, par value $1 per share, none issued
Balance beginning of year $ 80.6 $ 79.9 $ 69.0
Issuance of common stock 13.0 .7 10.9
- ------------------------------------------------------------------------------------------------------------------
BALANCE END OF YEAR 93.6 80.6 79.9
- ------------------------------------------------------------------------------------------------------------------
PREMIUM ON CAPITAL STOCK:
Balance beginning of year 972.3 965.1 777.6
Issuance of common stock 290.7 7.2 187.5
Other (9.5) -- --
- ------------------------------------------------------------------------------------------------------------------
BALANCE END OF YEAR 1,253.5 972.3 965.1
- ------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS:
Balance beginning of year 152.8 125.3 106.2
Net income 132.2 122.1 105.8
Dividends on preference stock -- (.3) (2.1)
Dividends on common stock, $1.20 per share in 1998,
$1.17 in 1997, and $1.17 in 1996 (95.0) (94.3) (84.6)
- ------------------------------------------------------------------------------------------------------------------
BALANCE END OF YEAR 190.0 152.8 125.3
- ------------------------------------------------------------------------------------------------------------------
Treasury stock, at cost (2,159,330 shares at December 31, 1998,
352,613 shares at December 31, 1997 and 343,211 shares at
December 31, 1996) (53.2) (10.8) (6.4)
Currency translation adjustment (37.6) (31.3) (5.9)
- ------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY $ 1,446.3 $ 1,163.6 $ 1,158.0
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
ALL SHARE AND PER SHARE AMOUNTS HAVE BEEN RESTATED FOR THE 3-FOR-2 STOCK SPLIT.
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
Dollars in millions 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income $ 132.2 $ 122.1 $ 105.8
Unrealized translation adjustments (6.3) (25.4) .5
- ------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 125.9 $ 96.7 $ 106.3
- ------------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
42
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
Dollars in millions 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $132.2 $122.1 $105.8
Adjustments to reconcile net income to net cash provided:
Depreciation, depletion and amortization 150.0 129.6 125.4
Provision for asset impairments 27.7 26.5 --
Net changes in price risk management assets and liabilities 100.8 84.3 (33.7)
Deferred taxes and investment tax credits 61.7 49.0 34.5
Equity in earnings from investments and partnerships (125.1) (68.8) (108.7)
Dividends from investments and partnerships 48.9 36.0 42.7
Minority interests 5.6 6.5 8.0
Write-off of deferred merger costs, net of termination fee received -- -- 11.0
Loss on retirement of debt, net -- 7.2 --
Cumulative effect of software accounting change, net -- 4.8 --
Changes in certain assets and liabilities, net of effects
of acquisitions and restructuring
Accounts receivable, net 64.7 (385.6) (506.2)
Accounts receivable sold (32.0) 50.0 61.6
Inventories and supplies (100.5) (.7) 1.6
Prepayments and other (13.6) (27.4) (14.8)
Accounts payable (101.9) 408.5 513.5
Accrued liabilities, net 36.8 (28.5) 15.2
Other 21.5 (64.5) 6.9
- --------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM OPERATING ACTIVITIES 276.8 349.0 262.8
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (121.8) (133.2) (134.3)
Purchase of utility and other business -- -- (138.1)
Investments in international businesses (520.0) (2.8) (42.3)
Redemption of investment in debt securities 101.1 -- --
Investments in energy related properties (33.8) (28.4) (26.4)
Other (.6) (38.2) (70.5)
- --------------------------------------------------------------------------------------------------------------
CASH USED FOR INVESTING ACTIVITIES (575.1) (202.6) (411.6)
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock 303.7 7.9 198.4
Retirement of preference stock -- (25.0) --
Treasury stock acquired (42.3) (4.4) (6.4)
Issuance of long-term debt 267.0 169.0 129.7
Retirement of long-term debt (216.4) (108.7) (22.2)
Short-term borrowings (repayments), net 121.8 (138.2) (37.6)
Cash dividends paid (95.0) (94.6) (86.7)
Other (9.5) -- --
- --------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM (USED FOR)FINANCING ACTIVITIES 329.3 (194.0) 175.2
- --------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 31.0 (47.6) 26.4
Cash and cash equivalents at beginning of year 89.5 137.1 110.7
- --------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $120.5 $ 89.5 $137.1
- --------------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
43
<PAGE>
NOTE 1:
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
UtiliCorp United Inc. is an international energy and energy solutions provider
headquartered in Kansas City, Missouri. We operate lines of business in the
following financial reporting segments: Regulated Businesses and Aquila Energy
(Aquila). Through locally based managements we operate our international
businesses as stand-alone companies or investments. Together these comprise the
International segment.
The main activity of Regulated Businesses is operating domestic utilities
that distribute and transmit electricity and natural gas. Our generation
facilities produce electricity in the U.S., primarily for our own distribution
system. We sell the rest of the output outside our service areas. We also
provide appliance maintenance and repair and market natural gas. Aquila markets
wholesale energy, gathers, transports and processes natural gas and gas liquids,
and holds interests in independent power projects. Aquila Energy Corporation is
a wholly-owned subsidiary of UtiliCorp. Aquila Gas Pipeline Corporation (AGP),
82%-owned by Aquila, operates the gas gathering and processing businesses,
located in Texas and Oklahoma.
Our utilities are in eight states, one Canadian province and New Zealand.
We market natural gas and electricity throughout the U.S. and in parts of
Canada, and market natural gas in the United Kingdom (U.K.). We also have
various investments in Australia and Jamaica.
USE OF ESTIMATES
We prepared these financial statements in conformity with generally accepted
accounting principles and made certain estimates and assumptions that affect the
reported amounts of assets and liabilities. Our estimates and assumptions affect
the disclosure of contingent assets and liabilities in this report and reported
amounts of sales and expenses during the reporting period. Actual results could
differ from those estimates. Our accounting policies conform to generally
accepted accounting principles.
PRINCIPLES OF CONSOLIDATION
Our consolidated financial statements include all of UtiliCorps operating
divisions and majority-owned subsidiaries. We use equity accounting for
investments of which we own between 20% and 50%. We eliminate any significant
inter-company accounts and transactions.
PROPERTY, PLANT AND EQUIPMENT
We show property, plant and equipment at cost. We expense repair and maintenance
costs as incurred. Depreciation is provided on a straight-line basis over the
estimated lives for utility plant by applying composite average annual rates.
These range from 2.1% to 4.2%, as approved by regulatory authorities. When
property is replaced, removed or abandoned, its cost, together with the costs of
removal less salvage, is charged to accumulated depreciation. We depreciate
gathering, processing and other energy related property using a composite
average annual rate of 4.0%. We depreciate remaining non-regulated property,
plant and equipment on a straight-line basis over their estimated lives, ranging
from three to 50 years.
SALES RECOGNITION
We recognize sales as products and services are delivered, except for trading
and energy marketing activities. These are discussed below.
For North American trading and energy marketing activities, we use the
mark-to-market method of accounting. Under that method, trading and energy
marketing activities are recorded at fair value, net of future servicing costs
and reserves. When the portfolio's market value changes (primarily due to newly
originated transactions and the effect of price changes) the change is
recognized as gains or losses in the period of change within the sales caption.
We record the resulting unrealized gains and losses as price risk management
assets and liabilities.
INCOME TAXES
Our financial statements use the liability method to reflect income taxes. To
estimate deferred tax assets and liabilities we apply current tax regulations at
the end of a reporting period to the cumulative temporary differences between
the tax bases of assets and liabilities and their reported amounts in the
financial statements. We amortize deferred investment tax credits over the lives
of the related properties.
CASH EQUIVALENTS AND CASH FLOW INFORMATION
Cash includes cash in banks and temporary investments with an original maturity
of three months or less. As of December 31, 1998, 1997 and 1996, our cash held
in foreign countries was $41.7 million, $74.5 million and $86.7 million,
respectively.
Cash payments for interest, taxes and supplemental disclosures relating to
acquisition activities are presented below:
<TABLE>
<CAPTION>
In millions 1998 1997 1996
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Cash paid during the year for:
Interest, net of amount capitalized $132.4 $131.4 $132.1
Income taxes 50.1 61.9 49.1
- ---------------------------------------------------------------------------
Liabilities assumed in acquisitions:
Fair value of assets acquired $609.7 $ -- $ 7.0
Cash paid for acquisitions 520.0 -- --
Liabilities assumed 89.7 -- 7.0
- ---------------------------------------------------------------------------
</TABLE>
44
<PAGE>
EARNINGS PER COMMON SHARE*
The table below shows how we calculated diluted earnings per share and diluted
shares outstanding. Basic earnings per share and basic weighted average shares
are the starting point in calculating the dilutive measures. To calculate basic
earnings per share, divide earnings available into weighted average shares
without adjusting for dilutive items.
<TABLE>
<CAPTION>
In millions except per share 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Earnings available for common shares $ 132.2 $ 121.8 $ 103.7
Convertible bonds .2 .3 .3
- ---------------------------------------------------------------------------------------------------------------
Earnings available for common shares after assumed
conversion of dilutive securities $ 132.4 $ 122.1 $ 104.0
- ---------------------------------------------------------------------------------------------------------------
EARNINGS PER SHARE:
BASIC--
Earnings before extraordinary item and cumulative
effect of software accounting change $ 1.65 $ 1.66 $ 1.46
Loss on retirement of debt -- (.09) --
Cumulative effect of software accounting change -- (.06) --
- ---------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 1.65 $ 1.51 $ 1.46
- ---------------------------------------------------------------------------------------------------------------
DILUTED
Earnings before extraordinary item and cumulative
effect of software accounting change $ 1.63 $ 1.66 $ 1.46
Loss on retirement of debt -- (.09) --
Cumulative effect of software accounting change -- (.06) --
- ---------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE $ 1.63 $ 1.51 $ 1.46
- ---------------------------------------------------------------------------------------------------------------
Weighted average number of common shares used in
basic earnings per share 80.07 80.42 70.81
Per share effect of dilutive securities:
Stock options .77 .18 --
Convertible bonds .34 .40 .48
- ---------------------------------------------------------------------------------------------------------------
Weighted number of common shares and dilutive potential
common stock used in diluted earnings per share 81.18 81.00 71.29
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
* ALL SHARE AND PER SHARE AMOUNTS HAVE BEEN RESTATED FOR THE 3-FOR-2 STOCK
SPLIT.
CURRENCY ADJUSTMENTS
We translate the financial statements of our foreign subsidiaries and
operations into U.S. dollars using the average monthly exchange rate during
the period for income statement items. We use the year-end exchange rate for
balance sheet items. When translating foreign currency-based assets and
liabilities to U.S. dollars, we show any differences between accounts as
translation adjustments in common shareowners' equity. For income statement
accounts we show all changes in foreign currency relative to the U.S. dollar
within the consolidated statements of income.
SOFTWARE COSTS
We capitalize the costs of internally-developed software that qualifies for
capitalization under generally accepted accounting principles. We expense those
costs that do not qualify. Typical capitalized costs include software coding and
testing. Typical expensed costs include training and data conversion costs.
STOCK-BASED COMPENSATION
We issue stock options to employees from time to time and account for these
options under Accounting Principles Board Opinion No. 25 (APB 25). All stock
options issued are granted at the common stock's current market price. This
means we record no compensation expense related to stock options. We also
offer employees a 15% discount from the market price of our common stock.
Since we record options and discounts under APB 25, we must disclose the
proforma compensation expense and earnings per share (dilutive method) as if
we reflected the estimated fair value of options and discounts as
compensation at the date of grant or issue. For the years ended December 31,
1998, 1997, and 1996, our proforma compensation expense would be $10.1 million,
$4.9 million and $1.5 million, respectively. Our proforma earnings per share
would have been reduced by $.07, $.03, and $.01 for the years ended
December 31, 1998, 1997 and 1996, respectively.
45
<PAGE>
NOTE 2:
A. TRADING ACTIVITIES:
PRICE RISK MANAGEMENT ACTIVITIES
We trade energy commodity contracts daily. Our trading activities attempt to
match our portfolio of physical and financial contracts to current or
anticipated market conditions. Within the trading portfolio, we take certain
positions to hedge physical sale or purchase contracts and we take certain
positions to take advantage of market trends and conditions. We record most
energy contracts--both physical and financial--at fair market value. Changes in
value are reflected in the consolidated statement of income. We use all forms of
financial instruments including futures, forwards, swaps and options. Each
type of financial instrument involves different risks. We believe financial
instruments help us manage our exposure to changes in market prices and take
advantage of selected arbitrage opportunities.
We refer to these transactions as price risk management activities.
MARKET RISK
The company's price risk management activities involve offering fixed price
commitments into the future. The contractual amounts and terms of these
financial instruments at December 31, 1998, are shown below:
<TABLE>
<CAPTION>
Dollars in millions FIXED PRICE PAYOR FIXED PRICE RECEIVER MAXIMUM TERM IN YEARS
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ENERGY COMMODITIES:
Gas (trillion BTUs) 4,454.8 4,201.9 12
Electricity (megawatt-hours) 2,421,440 2,238,176 1
- ------------------------------------------------------------------------------------------------------------
FINANCIAL PRODUCTS:
Interest rate instruments $2,507 $631 12
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Although we attempt to balance our physical and financial contracts in
terms of quantities and contract performance, net open positions typically
exist. We will at times create a net open position or allow a net open position
to continue when we believe that future price movements will increase the
portfolio's value. To the extent we have an open position, we are exposed to
fluctuating market prices that may adversely impact our financial position or
results from operations.
We measure the risk in our trading portfolio using value-at-risk
methodologies, to simulate forward price curves in the energy markets and
estimate the size of future potential losses. The quantification of market risk
using value-at-risk methodologies provides a consistent measure of risk across
diverse energy markets and products. The use of this method requires a number of
key assumptions, such as:
- Selection of a confidence level (we use 95%).
- Estimated holding period (we use three days).
- Use of historical estimates of volatility and correlation with recent
activity more heavily weighted.
At December 31, 1998, our value at risk was:
<TABLE>
<CAPTION>
In millions (UNAUDITED)
- ----------------------------------------------
<S> <C>
Electricity $.7
Natural gas 2.2
- ----------------------------------------------
</TABLE>
We also use additional risk control mechanisms such as stress testing,
daily loss limits and commodity position limits as well as daily monitoring of
the trading activities by an independent function.
MARKET VALUATION
The market prices used to value price risk management activities reflect our
best estimate of market prices considering various factors, including closing
exchange and over-the-counter quotations, time value of money and price
volatility factors underlying the commitments. We adjust market prices to
reflect the potential impact of liquidating our position in an orderly manner
over a reasonable period of time under present market conditions.
We consider a number of risks and costs associated with the future
contractual commitments included in our energy portfolio, including credit risks
associated with the financial condition of counterparties, product
46
<PAGE>
location (basis) differentials and other risks which our policy dictates. The
value of all forward contracts is discounted to December 31, 1998 using an
estimated rate. We continuously monitor the portfolio and value it daily based
on present market conditions. The following table displays the market values of
energy transactions at December 31, 1998 and 1997 and the average value for the
year ended December 31, 1998 and 1997:
<TABLE>
<CAPTION>
Price Risk Management Assets Price Risk Management Liabilities
---------------------------- ---------------------------------
Dollars in millions Average Value December 31, 1998 Average Value December 31, 1998
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Independent power producers $147.6 $165.4 $ -- $ --
Financial institutions 14.1 2.8 37.6 42.5
Oil and gas producers 31.4 38.4 24.9 34.1
Gas transmission 44.3 41.3 148.4 126.1
Energy marketers 116.5 90.4 83.6 46.6
Other 34.1 50.3 66.2 198.8
- ------------------------------------------------------------------------------------------------------------------------
Gross value 388.0 388.6 360.7 448.1
Reserves -- -- 53.1 52.5
- ------------------------------------------------------------------------------------------------------------------------
Total $388.0 $388.6 $413.8 $500.6
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Price Risk Management Assets Price Risk Management Liabilities
---------------------------- ---------------------------------
Dollars in millions Average Value December 31, 1997 Average Value December 31, 1997
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Independent power producers $158.7 $162.2 $ -- $ --
Financial institutions 16.1 15.4 28.7 36.6
Oil and gas producers 9.0 13.1 20.1 25.2
Gas transmission 14.6 31.7 44.2 144.4
Energy marketers 25.4 52.2 14.7 22.1
Other 5.6 8.4 3.8 5.5
- ------------------------------------------------------------------------------------------------------------------------
Gross value 229.4 283.0 111.5 233.8
Reserves -- -- 57.9 60.4
- ------------------------------------------------------------------------------------------------------------------------
Total $229.4 $283.0 $169.4 $294.2
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
Future changes in the creditworthiness of our counterparties change the
value of our portfolio. We adjust the value of contracts and set dollar limits
with counterparties based on our assessment of their credit quality.
As of December 31, 1998, the future cash flow requirements, net of margin
deposits, related to these financial instruments were $15.1 million. Margin
deposits are required on certain financial instruments to address significant
fluctuations in market prices.
The value of price risk management assets is concentrated into three
contracts representing 36% of total asset value of the portfolio. This
concentration of customers may impact the companys overall exposure to credit
risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions.
B. NON-TRADING ACTIVITIES--HEDGING
INSTRUMENTS
We enter into forwards, futures and other contracts related to our commodity
businesses solely to hedge future production. The estimated fair value and cash
flow requirements for these financial instruments are based on the market prices
in effect at the financial statement date and do not necessarily reflect our
entire trading portfolio.
47
<PAGE>
NOTE 3:
ACCOUNTS RECEIVABLE
Our accounts receivable on the Consolidated Balance Sheets are comprised as
follows:
<TABLE>
<CAPTION>
December 31,
------------------------
In millions 1998 1997
- ------------------------------------------------------------------------------------
<S> <C> <C>
Accounts receivable, net of
allowance for bad debt $1,302.6 $1,328.3
Unbilled revenue 82.9 116.8
Accounts receivable sale program (248.0) (280.0)
- ------------------------------------------------------------------------------------
TOTAL $1,137.5 $1,165.1
- ------------------------------------------------------------------------------------
</TABLE>
We sell, on a continuing basis, up to $280 million of eligible accounts
receivable on a limited recourse basis. The financial institutions that buy our
receivables charge a fee based on the dollar amount sold which is reflected as
an expense in the consolidated statements of income. Our consolidated statements
of income reflect fees associated with these sales of (in millions) $16.0 in
1998, $15.2 in 1997, and $12.2 in 1996.
NOTE 4:
PROPERTY, PLANT AND EQUIPMENT
The components of property, plant and equipment are as
follows:
<TABLE>
<CAPTION>
December 31,
--------------------
In millions 1998 1997
- --------------------------------------------------------------------------
<S> <C> <C>
Electric utility $2,527.4 $1,766.2
Gas utility 1,164.1 1,128.7
Gas gathering and pipeline systems 587.8 555.8
Other 425.8 261.8
Construction in process 57.0 88.2
- --------------------------------------------------------------------------
4,762.1 3,800.7
Less depreciation, depletion
and amortization 1,448.2 1,320.4
- --------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET $3,313.9 $2,480.3
- --------------------------------------------------------------------------
</TABLE>
Our property, plant and equipment includes acquisition-related intangibles
that are being amortized over useful lives not exceeding 40 years.
CUMULATIVE EFFECT OF SOFTWARE
ACCOUNTING CHANGE
In 1997, we changed our method of accounting for internally developed software
costs to conform with the new requirements of an accounting standard that became
effective November 20, 1997. This accounting change reduced 1997 net income by
$4.8 million and is shown in our consolidated statement of income as a
cumulative effect of software accounting change.
NOTE 5:
ASSET IMPAIRMENTS
We have adjusted the reported value of certain assets over the last three years.
Although it was a requirement that assets reflect realizable values, it was not
until the passage of Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of" (SFAS 121), that impairment provisions were determined on a
consistent basis and methodology. The table below summarizes the impairment
provisions we have recorded since 1996 and the related reasons.
<TABLE>
<CAPTION>
For the years ended December 31,
--------------------------------
In millions 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Retail marketing assets (a) $13.2 $ -- $ --
Investment in EnergyOne, L.L.C. (b) 8.0 -- --
Investment in a power project (c) 6.5 -- --
Royalty interest (d) -- 15.5 --
Technology-related investment (e) -- 11.0 --
- --------------------------------------------------------------------------------
TOTAL $27.7 $26.5 --
- --------------------------------------------------------------------------------
</TABLE>
(a) In June 1998, we revised our strategic plan to curtail our retail
activities. This revised strategy diminished the value of certain retail
assets and required an impairment provision to be recorded.
(b) In April 1998, we agreed with our partner to dissolve our partnership due
to unfavorable market conditions and unsatisfactory execution of its
strategy. As a result of this decision, the recorded value of EnergyOne,
L.L.C. became overstated related to liquidation values and an impairment
provision was recorded.
(c) In June 1998, we concluded that the cash flows from a power project would
not be sufficient to recover its recorded value. This project was exploring
certain methods to enhance cash flows, such as fuel mix changes, but based
on our analysis, we concluded that no viable alternatives existed to
improve operations. We recorded an impairment based on this analysis.
(d) In 1997, we reduced the carrying value of royalty interests that are tied
to the drilling success of some properties we sold in 1995. Based on
information from the company we sold the properties to, we concluded that
an impairment charge was necessary.
(e) In 1997, we wrote off our investment in a technology joint venture
organized to develop energy related innovations. When no marketable
products were developed we reassessed the value of this investment and
determined that future cash flows, if any, would not recover invested
costs.
48
<PAGE>
NOTE 6:
INVESTMENTS IN SUBSIDIARIES AND PARTNERSHIPS
Our consolidated balance sheet contains various equity investments as shown in
the table below. Our New Zealand investment is now fully consolidated within the
1998 balance sheet but before 1998, our New Zealand operations were equity
investments. The table below summarizes our investments and related equity
earnings.
<TABLE>
<CAPTION>
Investment Equity Earnings
at December 31, Year Ended December 31,
Ownership ----------------- ----------------------------
Dollars in millions at 12/31/98 Country 1998 1997 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
UAHL investment 34.0% Australia $221.9 $237.9 $69.1 $28.6 $42.7
UNZ investment (a)
WEL Energy Group Ltd. (WEL) -- New Zealand -- 39.6 11.3 4.5 6.2
Power New Zealand (PNZ) -- New Zealand -- 115.2 8.1 9.2 11.2
UtilCo Group partnerships (b) 17%--50% U.S. & Jamaica 193.7 199.7 33.4 29.6 48.5
Oasis Pipe Line Company (Oasis) (c) 35% United States 97.1 96.3 1.1 .9 .1
Other 7.1 2.5 2.1 (4.0) --
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL $519.8 $691.2 $125.1 $68.8 $108.7
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) We acquired a controlling interest in 1998 and as a result our New Zealand
investments are reflected on a consolidated basis.
(b) We own interests in 17 independent power projects located in seven states
and Jamaica. Of these, 16 are currently in commercial operation. These
investments are aggregated because individual investments are not
significant.
(c) In 1996, our Aquila Gas Pipeline (AQP) subsidiary acquired an equity
interest in a pipeline for $132.0 million. In 1997, AQP sold 5% of its
interest to another partner.
The summarized combined financial information of unconsolidated material equity
investments is presented below:
<TABLE>
<CAPTION>
December 31,
---------------------
In millions 1998 (a) 1997
- ----------------------------------------------------------------------
<S> <C> <C>
ASSETS:
Current assets $ 322.7 $ 338.1
Non-current assets 2,084.8 2,840.6
- ----------------------------------------------------------------------
TOTAL ASSETS $2,407.5 $3,178.7
- ----------------------------------------------------------------------
LIABILITIES AND EQUITY
Current liabilities $ 335.9 $ 449.8
Non-current liabilities 1,344.2 1,718.1
Equity 727.4 1,010.8
- ----------------------------------------------------------------------
TOTAL LIABILITIES AND EQUITY $2,407.5 $3,178.7
- ----------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
In millions 1998 (a) 1997 1996
- --------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING RESULTS:
Revenues $850.3 $1,294.7 $1,277.8
Costs and expenses 752.4 1,140.7 1,109.1
- --------------------------------------------------------------------------
NET INCOME $97.9 $ 154.0 $ 168.7
- --------------------------------------------------------------------------
</TABLE>
(a) Excludes UnitedNetworks since this subsidiary is reflected in the
consolidated statements.
NOTE 7:
NEW ZEALAND AND AUSTRALIA TRANSACTIONS
INTEREST IN NEW ZEALAND ELECTRIC UTILITIES
Through a series of transactions in 1998, we acquired an additional 48% of Power
New Zealand's common stock for approximately $245 million, increasing our
ownership to 78.6%. Concurrent with this acquisition, we sold our 39.6% interest
in New Zealand's WEL Energy Group, which we acquired throughout 1995, 1996 and
1997, and bought out the 21% minority shareholder in our New Zealand subsidiary,
UtiliCorp N.Z., Inc.
New Zealand's Electricity Industry Reform Act of 1998 requires all the
country's utilities to separate ownership of their lines (network) and supply
(generation and retail) businesses. Power New Zealand, with approximately 90% of
its assets and earnings in the lines area, on November 13 announced its
intention to remain in the network business and to exit the supply business. It
also agreed to purchase the Wellington-based lines assets of TransAlta New
Zealand Ltd. and to sell to TransAlta its retail electricity business serving
the Auckland area for a net expenditure by Power New Zealand of $238 million.
Because Power New Zealand's name transferred to TransAlta as part of the
retail business TransAlta acquired, the network business became UnitedNetworks
Limited on January 1, 1999.
49
<PAGE>
On November 20, Power New Zealand agreed to purchase the electric line
assets of neighboring power company TrustPower Limited for approximately $261
million. The assets became part of a greater network which includes parts of
metropolitan Auckland and other areas in the central and southern regions of
New Zealand's North Island. The TrustPower transaction closed in January
1999. Completion of the TransAlta and TrustPower transactions created the
country's largest electricity distribution network, serving about 468,000
customers.
INITIAL PUBLIC OFFERING--UNITED ENERGY LIMITED
In May 1998, United Energy Limited (UEL) sold 42% of its common stock to the
Australian public and as a result, we recorded a $45.3 million gain. The
partial sale to the public reduced our effective ownership percentage to 29%.
Concurrent with UEL's stock offering, we bought an additional 5% in UEL from
another company to bring our ownership in UEL to 34%. Prior to the common
stock sale, UEL repaid approximately $101 million in debt notes owed to us.
The management agreement between UEL and UtiliCorp remains in place.
NOTE 8: REGULATORY ASSETS
Our domestic utility operations are regulated by state or local authorities.
Our financial statements therefore include the economic effects of rate
regulation. This means our consolidated balance sheet shows some assets and
liabilities that would not be found on the balance sheet of a non-regulated
company. There is a risk that if the domestic utility industry deregulates,
we may have to remove the effects of regulation from our financial statements.
The following table lists the regulatory assets and liabilities recorded
at December 31, 1998 and 1997. These are primarily shown as deferred charges
and credits on the consolidated balance sheets.
<TABLE>
<CAPTION>
In millions 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C>
Income taxes $ 59.0 $ 55.2
Environmental liabilities 11.5 11.2
Debt-related costs 17.8 19.6
Regulatory accounting orders 6.4 8.4
Demand-side management programs 10.3 13.0
Other 9.2 15.3
- --------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS $ 114.2 $ 122.7
- --------------------------------------------------------------------------------
Regulatory Liabilities 17.7 16.8
- --------------------------------------------------------------------------------
NET REGULATORY ASSETS $ 96.5 $ 105.9
- --------------------------------------------------------------------------------
</TABLE>
NOTE 9: SHORT-TERM DEBT
Short-term debt includes the following components:
<TABLE>
<CAPTION>
December 31,
------------
Dollars in millions 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C>
Bank borrowing and other $ 235.6 $ 113.8
Commercial paper -- --
TOTAL $ 235.6 $ 113.8
- --------------------------------------------------------------------------------
Weighted average interest
rate at year end 4.31% 6.21%
- --------------------------------------------------------------------------------
</TABLE>
We have a $150 million commercial paper program supported by a $250
million revolving credit agreement. The credit agreement allows us to issue
commercial paper at a favorable interest rate. Our credit agreement contains
restrictive covenants and charges an annual commitment fee of .17% on the
unused portion.
During 1998 we put in place two New Zealand credit facilities that we
used to acquire additional shares in UnitedNetworks. These facilities have
the following terms.
<TABLE>
<CAPTION>
Dollars in millions
- -------------------------------------------------------------
Maximum Amount Interest Maturity
Amount Outstanding Rate Date
- -------------------------------------------------------------
<S> <C> <C> <C>
$NZ 425 $NZ 403.9 4.30% October 1999
$NZ 45 $NZ 42.4 4.47% June 1999
- -------------------------------------------------------------
</TABLE>
The outstanding balances from these credit facilities comprise the total
short-term debt balance at December 31, 1998. The interest rates may vary
with changes in the New Zealand bank bill rate and carry a commitment fee
of.20% on unused amounts.
50
<PAGE>
NOTE 10: LONG-TERM DEBT
This table summarizes the company's long-term debt:
<TABLE>
<CAPTION>
December 31,
------------
In millions 1998 1997
- ------------------------------------------------------------------------------------------
<S> <C> <C>
FIRST MORTGAGE BONDS:
Various, 9.94%*, due 1999-2008 $ 19.5 $ 20.6
SENIOR NOTES:
6.0% Series, retired April 1, 1998 -- 70.0
9.21% Series, due October 11, 1999 50.0 50.0
8.45% Series, due November 15, 1999 100.0 100.0
Aquila Southwest Energy 8.29% Series,
due September 15, 2002 50.0 62.5
6.875% Series, due October 1, 2004 150.0 150.0
6.375% Series, due June 1, 2005 100.0 100.0
6.70% Series, due October 15, 2006 100.0 100.0
8.2% Series, due January 15, 2007
130.0 130.0
10.5% Series, due December 1, 2020 55.9 55.9
9.0% Series, due November 15, 2021 150.0 150.0
8.0% Series, due March 1, 2023 125.0 125.0
SECURED DEBENTURES OF WEST KOOTENAY POWER:
9.15%*, due 2001-2023 66.2 71.3
CONVERTIBLE SUBORDINATED DEBENTURES:
6.625%, due July 1, 2011 (convertible into 337,500 common shares) 5.3 5.8
New Zealand Denominated Credit Facilities, due June 30, 1999
and January 15, 2002 379.2 64.7
Australian Denominated Credit Facility, due July 20, 2000 101.0 195.1
Other notes and obligations 42.5 57.3
- -----------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 1,624.6 1,508.2
Less current maturities 248.8 149.6
- -----------------------------------------------------------------------------------------
LONG-TERM DEBT, NET $ 1,375.8 $ 1,358.6
- -----------------------------------------------------------------------------------------
Fair value of long-term debt, including current maturities (a) $ 1,752.8 $ 1,581.1
- -----------------------------------------------------------------------------------------
</TABLE>
* WEIGHTED AVERAGE INTEREST RATE.
(a) THE FAIR VALUE OF LONG-TERM DEBT IS BASED ON CURRENT RATES AT WHICH THE
COMPANY COULD BORROW FUNDS WITH SIMILAR REMAINING MATURITIES.
Substantially all of our domestic utility plant is subject to the lien
of various mortgage indentures. We cannot issue additional mortgage bonds
under these indentures without directly securing certain Senior Notes equally
as any mortgage bond issue. Currently we have no plans to issue mortgage
bonds.
The amounts of long-term debt maturing in each of the next five years
and thereafter are shown at right:
In millions Maturing Amounts
- --------------------------------------------------------------
1999 $ 248.8
2000 164.5
2001 44.4
2002 243.0
2003 10.4
Thereafter 913.5
- --------------------------------------------------------------
TOTAL $ 1,624.6
- --------------------------------------------------------------
51
<PAGE>
RETIREMENT OF DEBT
In March 1997 we retired, at a premium, $69.1 million of our 10.5% series
senior notes that were to mature in 2020. This transaction resulted in an
extraordinary loss of $7.2 million, net of an income tax benefit of $4.5
million.
NEW ZEALAND DENOMINATED CREDIT FACILITIES
UtiliCorp South Pacific, Inc. (USP) has a $NZ135 million credit facility with
a consortium of banks that was used to finance a portion of the investments
made by UNZ. The interest rate fluctuates (4.36% at December 31, 1998) with
changes in the New Zealand bank bill rate. The credit facility matures on
June 30, 1999. A commitment fee of .20% applies to the unused portion of the
credit facility. UnitedNetworks has a three-year term loan facility to
finance the acquisitions of TransAlta's (December 1998) and TrustPower's
(January 1999) lines businesses. The maximum amount of the facility is $NZ 1
billion. The interest rate is fixed through series of swaps at 7.70%
AUSTRALIAN DENOMINATED CREDIT FACILITIES
We maintain a $A150 million credit facility with a bank that matures in July
2000. The interest rate for $A100 million of this facility fluctuates with
changes in the Australian bank bill rate. At December 31, 1998, $A100 million
was outstanding under the floating rate portion of this facility at a rate of
5.21%. The interest rate on the remaining $A50 million of this facility is
fixed at 7.48%, with $A50 million outstanding at December 31, 1998. A
commitment fee of .20% applies to the unused portion of the credit facility.
We also have a $A100 million credit facility with a consortium of banks
that matures in July 2000. The interest rate on this facility fluctuates with
changes in the Australian bank bill rate. At December 31, 1998, $A15 million
was outstanding at a rate of 5.33%. A commitment fee of .20% applies to the
unused portion of the credit facility.
NOTE 11: COMPANY-OBLIGATED PREFERRED SECURITIES
In June 1995, UtiliCorp Capital L.P. (UC), a limited partnership of which we
are the general partner, issued 4 million shares of 8.875% Cumulative Monthly
Income Preferred Securities, Series A, for $100 million. The limited
partnership interests represented by the preferred securities are redeemable
at the option of UC, after June 12, 2000, at $25 per preferred security plus
accrued interest and unpaid dividends.
Holders of the securities are entitled to receive dividends at an annual rate
of 8.875% of the liquidation preference value of $25. Dividends are payable
monthly and in substance are tax-deductible by the company. The securities are
shown as company-obligated mandatorily redeemable preferred securities of
partnership on the consolidated balance sheets. The dividends are shown as
minority interest in income of partnership in the consolidated statements of
income.
NOTE 12: CAPITAL STOCK
COMMON STOCK OFFERING
We have two types of authorized common stock--unclassified common stock and
Class A common stock. No Class A common stock is issued or outstanding. As of
December 31, 1998, we had no restrictions on our ability to pay cash
dividends.
COMMON STOCK SPLIT
In November 1998, our Board of Directors approved a 3-for-2 common stock
split. The stock split is effective March 12, 1999 and all share amounts,
share prices and per share figures have been restated.
STOCKHOLDER RIGHTS PLAN
Our Board adopted a rights plan and declared a dividend distribution of one
right for each outstanding common share. The rights are not currently
exercisable. Each right, when exercisable, would entitle each right holder to
purchase one one-thousandth of a share of Series A Participating cumulative
Preference Stock at a price of $77. The rights become exercisable if a person
has acquired 15% of the outstanding common stock. Once the rights become
exercisable, each rights holder can purchase common stock in the company at a
market value twice the exercise price of the right.
DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
We offer to current and potential shareholders a Dividend Reinvestment and
Common Stock Purchase Plan (the Stock Plan).
The Stock Plan allows participants to purchase up to $10,000 per month
of common stock at a five-day average market price, without sales
commissions. The Stock Plan also allows members to reinvest dividends into
additional common shares at a 5% discount.
For the year ended December 31, 1998, 1,125,000 shares were issued under
the Stock Plan. As of December 31, 1998, 6,206,537 shares were available to
issue under this plan.
EMPLOYEE STOCK PURCHASE PLAN
Participants in our Employee Stock Purchase Plan have the opportunity to buy
shares of common stock at a reduced price through regular payroll deductions
and/or lump sum deposits of up to 20% of the employee's base salary.
Contributions are credited to the participant's account throughout an option
period. At the end of the option period, the participant's total account
balance is applied to the purchase of common stock. The shares are purchased
at 85% of the lower of the market price
52
<PAGE>
on the first day or the last day of the option period. Participants must be
enrolled in the Plan as of the first day of an option period in order to
participate in that option period.
RESTATED SAVINGS PLAN
A defined contribution plan, the Restated Savings Plan (Savings Plan), covers
all of our full-time and eligible part-time employees. Participants may
generally elect to contribute up to 15% of their annual pay on a before- or
after-tax basis subject to certain limitations. The company generally matches
contributions up to 6%. Participants may direct their contributions into five
different investment options. All company matching contributions are in
UtiliCorp common stock. The Savings Plan also includes a stock contribution
fund to which the company can contribute an additional amount of company
common stock for participants.
STOCK INCENTIVE PLAN
Our Stock Incentive Plan enables the company to grant 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. They grant 10 years after the date of grant.
EMPLOYEE STOCK OPTION PLAN
The Board approved the establishment of an Employee Stock Option Plan in
1991. This Plan provides for the granting of up to 1.5 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 1988 and 1992, respectively, options for 1,278,713 and
1,114,350 shares were granted to employees. The exercise prices of these
options are $24.02 and $18.21, respectively.
This table summarizes stock options as of December 31, 1998 and 1997:
<TABLE>
<CAPTION>
Shares 1998 1997
- ------------------------------------------------------------
<S> <C> <C>
BEGINNING BALANCE 3,764,441 3,300,675
Granted 2,706,526 1,684,530
Exercised (803,565) (922,935)
Cancelled (226,999) (297,829)
- ------------------------------------------------------------
ENDING BALANCE 5,440,403 3,764,441
- ------------------------------------------------------------
WEIGHTED AVERAGE PRICES:
Beginning balance $ 18.65 $ 18.63
Granted price 23.94 18.53
Exercised price 18.79 18.40
Cancelled price 20.47 18.47
Ending balance 21.15 18.65
- ------------------------------------------------------------
</TABLE>
At December 31, 1998, total exercisable restricted stock awards and
stock options were 670,908 shares (at prices ranging between $14.59 and
$25.00).
NOTE 13: INCOME TAXES
Income tax expense consists of the following components:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
In millions 1998 1997 1996
- ---------------------------------------------------------------------
<S> <C> <C> <C>
CURRENTLY PAYABLE:
Federal $ 33.9 $ 27.1 $ 35.0
Foreign 1.7 7.1 14.2
State 6.5 6.5 5.5
DEFERRED:
Federal 41.5 42.1 23.0
State 4.2 8.2 4.3
Investment tax credit
amortization (1.2) (1.3) (1.3)
- ---------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $ 86.6 $ 89.7 $ 80.7
- ---------------------------------------------------------------------
</TABLE>
The principal components of deferred income taxes consist of the following:
<TABLE>
December 31,
------------
In millions 1998 1997
- -----------------------------------------------------------
<S> <C> <C>
DEFERRED TAX ASSETS:
Alternative maximum carryforward $ 93.4 $ 98.3
DEFERRED TAX LIABILITIES AND CREDITS:
Accelerated depreciation and
other plant differences:
Regulated 180.5 167.5
Non-regulated 186.7 168.9
Regulatory asset--SFAS 109 42.4 38.6
Mark-to-market reserve 50.4 25.8
Other, net 62.9 60.2
- -----------------------------------------------------------
TOTAL DEFERRED TAX LIABILITIES
AND CREDITS 522.9 461.0
DEFERRED INCOME TAXES AND
CREDITS, NET $ 429.5 $ 362.7
- -----------------------------------------------------------
</TABLE>
53
<PAGE>
Our effective income tax rates differed from the statutory federal income
tax rates primarily due to the following:
<TABLE>
<CAPTION>
December 31,
--------------------------
Percent 1998 1997 1996
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Statutory Federal Income Tax Rate 35.0% 35.0% 35.0%
TAX EFFECT OF:
Temporary difference passed
through, primarily
removal costs -- -- .2
Investment tax credit
amortization (.5) (.6) (.7)
State income taxes, net of
federal benefit 4.9 5.8 5.8
Difference in tax rate of
foreign subsidiaries (3.1) (1.9) (.7)
Other 3.3 1.8 3.7
- ---------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 39.6% 40.1% 43.3%
- ---------------------------------------------------------------------
</TABLE>
We had alternative minimum tax credit carryforwards of approximately
$93.4 million at December 31, 1998. Alternative minimum tax credits can be
carried forward indefinitely. The company has not recorded a valuation
allowance against its tax credit carryforwards.
We have made no provision for U.S. income taxes on undistributed earnings
from our international businesses ($145.0 million at December 31, 1998)
because it is our intention to reinvest those earnings. If we distribute
those earnings in the form of dividends, we may be subject to both foreign
withholding taxes and U.S. income taxes net of allowable foreign tax credits.
Consolidated income before income taxes for the years ended December 31,
1998, 1997 and 1996 included (in millions) $70.5, $13.6 AND $39.2,
respectively, from international operations.
NOTE 14: EMPLOYEE BENEFITS
PENSIONS
The following table shows the funded status of our pension plans and the
amounts included in the consolidated balance sheets and statements of income.
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
------------------------------------ --------------------------------------
Dollars in millions 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at start of year $ 205.4 $ 185.9 $ 183.9 $ 42.6 $ 39.0 $ 40.2
Service cost 7.7 6.2 6.5 .7 .7 1.0
Interest cost 14.4 13.8 13.0 2.7 2.8 2.9
Plan participants' contribution .6 .7 .7 .8 .8 .8
Amendments 8.9 .5 .4 .3 (.1) --
Actuarial (gain) loss (1.2) 8.3 (7.1) 1.6 .6 (3.4)
Benefits paid (12.1) (8.5) (11.8) (6.3) (1.1) (2.5)
Foreign Currency Exchange changes (2.4) (1.5) .3 (.2) (.1) --
- --------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $ 221.3 $ 205.4 $ 185.9 $ 42.2 $ 42.6 $ 39.0
- --------------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at start of year $ 240.1 $ 208.7 $ 191.7 $ 4.8 $ .5 $ .9
Actual return on plan assets (.5) 38.8 26.0 .3 .1 --
Employer contribution 1.6 1.8 1.8 7.8 4.5 1.4
Plan participants' obligation .6 .7 .7 .8 .8 .8
Benefits paid (12.1) (8.5) (11.7) (6.3) (1.1) (2.6)
Foreign Currency Exchange changes (2.1) (1.4) .2 -- -- --
- --------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 227.6 $ 240.1 $ 208.7 $ 7.4 $ 4.8 $ .5
- --------------------------------------------------------------------------------------------------------------------------
Funded status $ 6.3 $ 34.7 $ 22.8 $(34.8) $ (37.8) $ (38.5)
Unrecognized transition amount (8.9) (10.1) (11.3) 28.3 30.4 32.4
Unrecognized net actuarial (gain) loss 19.4 (2.4) 8.2 (8.8) (7.7) (8.5)
Unrecognized prior service cost 9.8 1.1 .9 .3 -- --
- --------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 26.6 $ 23.3 $ 20.6 $(15.0) $ (15.1) $ (14.6)
- --------------------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE ASSUMPTIONS AS OF
SEPTEMBER 30:
Discount rate 6.75% 7.17% 7.60% 6.75% 7.00% 7.50%
Expected return on plan assets 9.73% 9.73% 8.0-10.0% 7.00% 10.00% 8.25%
Rate of compensation increase 5.09% 5.36% 5.0-5.4% 5.40% 5.40% 5.0-5.4%
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
54
<PAGE>
For measurement purposes, we assumed a 6.00% annual rate of increase in
the per capita cost of covered health benefits for each future fiscal year.
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
-------------------------------- ----------------------------
Dollars in millions 1998 1997 1996 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 7.7 $ 6.2 $ 6.5 $ .7 $ .7 $ 1.0
Interest cost 14.4 13.8 13.0 2.7 2.8 2.9
Expected return on plan assets (22.8) (19.8) (18.3) (.3) (.2) --
Amortization of transition amount (1.2) (1.2) (1.2) 2.0 2.0 2.0
Amortization of prior service cost -- -- (.1) -- -- --
Recognized net actuarial (gain) loss -- -- .4 (.2) (.3) --
Regulatory adjustment .8 .8 .9 -- -- --
- ----------------------------------------------------------------------------------------------------------
NET PERIODIC BENEFIT COST $ (1.1) $ (.2) $ 1.2 $ 4.9 $ 5.0 $ 5.9
- ----------------------------------------------------------------------------------------------------------
</TABLE>
The U.S. pension plan was amended effective October 1, 1998 to provide
the same pension benefits for almost all participants. In one location, we
recorded pension expense using a modified amortization of gains and losses
consistent with the rate treatment allowed for this cost.
Our health care plans are contributory, with participants' contributions
adjusted annually. The life insurance plans are non-contributory. We have
assumed in estimating future health care costs future cost-sharing changes.
The expense recognition for health care costs does not necessarily match the
cost estimates due to certain differences in regulatory accounting at
domestic utility operations.
The assumed health care cost trends significantly affect the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects for Fiscal Year
1998.
<TABLE>
<CAPTION>
1 Percentage-Point
------------------
In millions Increase Decrease
- -------------------------------------------------
<S> <C> <C>
Effect on total of
service and interest
cost components $ .4 $ (.3)
Effect on post-retirement
benefit obligation 3.5 (2.9)
- -------------------------------------------------
</TABLE>
In addition to the defined benefit retirement plans and health care
plans, we contribute to a defined contribution savings plan. Company
contributions were $8.4 million and $8.1 million during the plan years ending
December 1998 and 1997, respectively.
NOTE 15: COMMITMENTS AND CONTINGENCIES
Commitments
We have various commitments for the next five years relating to power and gas
supply commitments, fixed price sales obligations, and lease and rental
commitments. A summary is below. As with any estimates, the actual amounts
paid or received could differ materially.
<TABLE>
<CAPTION>
Dollars in millions except per unit 1999 2000 2001 2002 2003
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Capital expenditures $ 230.0 $ 316.0 $ 326.0 $ 185.0 $ 189.0
Future minimum lease payments $ 23.6 $ 30.9 $ 35.9 $ 34.7 $ 33.8
Purchased power obligations $ 63.0 $ 60.0 $ 37.6 $ 23.7 $ 23.6
Purchased power obligations (GIGAWATTS) 1,149 989 827 308 308
Cash flow obligation on prepaid gas sales $ 29.6 $ 32.9 $ 34.2 $ 35.8 $ 40.9
- ---------------------------------------------------------------------------------------------------------------------------
Coal contracts $ 43.8 $ 44.0 $ 31.1 $ 30.0 $ 30.9
Price ranges ------------------$12.85 to $23.75 per ton----------------
- ---------------------------------------------------------------------------------------------------------------------------
Fixed price sales physical obligations (TRILLION BTUs) 637.7 101.8 40.9 34.0 36.0
Price ranges ------------------$1.24 to $4.10 per MCF-------------------
- ---------------------------------------------------------------------------------------------------------------------------
Fixed price purchase physical obligations (TRILLION BTUs) 590.1 49.6 19.2 3.2 --
Price ranges -----------------$1.23 to $3.30 per MCF-------------------
- ---------------------------------------------------------------------------------------------------------------------------
Fixed price sales obligations (GIGAWATTS) 33,166 655 -- -- --
Price ranges -----------------$11.00 to $128.00 per MWH----------------
- ---------------------------------------------------------------------------------------------------------------------------
Fixed price purchase obligations (GIGAWATTS) 33,749 534 -- -- --
Price ranges -----------------$12.00 to $123.00 per MWH----------------
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
55
<PAGE>
Future minimum lease payments primarily relate to our interest in the
Jeffrey Energy Center, peaking turbines, coal cars and office space. Rent
expense for the years 1998, 1997 and 1996 was (in millions) $31.1, $32.1 and
$29.4, respectively.
A 1998 court ruling required United Gas to pay the gas cost amount in
accordance with a contract that was subject to a legal dispute. In addition,
United Gas is required to pay interest to the supplier on the $38 million. We
estimate this will cost $6.8 million.
In 1998 we entered into a 15-year agreement to obtain the rights to
dispatch 267 megawatts of power from facilities currently being built by a
third party. As part of the agreement we will provide the natural gas to the
power plant and will be able to dispatch the power. The plant is expected to
be available in June 2000.
ENVIRONMENTAL
We are subject to various environmental laws. These include regulations
governing air and water quality and the storage and disposal of hazardous or
toxic wastes. We continually assess ways to ensure we comply with laws and
regulations on hazardous materials and hazardous waste and remediation
activities.
We own or previously operated 29 former manufactured gas plants (MGPs)
which may, or may not, require some form of environmental remediation. We
have contacted appropriate federal and state agencies and are working to
determine what, if any, specific cleanup activities these sites may require.
As of December 31, 1998, we estimate cleanup costs on our identified MGP
sites to be $10.0 million. This estimate could change materially when we have
investigated further. It could also be affected by the actions of
environmental agencies and the financial viability of other responsible
parties. Ultimate liability also may be affected significantly if we are held
responsible for parties unable to contribute financially to the cleanup
effort.
We have received favorable rate orders that enable us to recover
environmental cleanup costs in certain jurisdictions. In other jurisdictions,
there are favorable regulatory precedents for recovery of these costs. We
are also pursuing recovery from insurance carriers and other potentially
responsible parties.
In December 1996, the U.S. Environmental Protection Agency (EPA)
published its final rule for nitrous oxide (NOx) emissions as required by
the Clean Air Act Amendments of 1990. The new NOx regulations require that we
install additional emissions control equipment at one of our power plants by
January 1, 2000.
In October 1998, the EPA published new air quality standards to further
reduce the emission of NOx. These more strict standards will require us to
install new equipment on our baseload coal units in Missouri that we
estimate will cost $35 million. The ultimate cost is under debate and subject
to change. The new standards as written are effective in May 2003.
We do not expect final resolution of these environmental matters to have a
a material adverse affect on our financial position or results of operations.
RATE PROCEEDING
We filed and have pending a request to increase our gas and electric rates in
West Virginia by $4.7 million and $2.9 million, respectively. We expect final
rates in late 1999.
OTHER
The company is subject to various legal proceedings and claims that arise in
the ordinary course of business operations. We do not expect the amount of
liability, if any, from these actions to materially affect our consolidated
financial position or results of operations.
NOTE 16: SEGMENT INFORMATION
A. BUSINESS LINES
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
Dollars in millions 1998 1997 1996
- -------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
SALES:
Regulated Businesses--
Electric $ 616.6 4.9% $ 557.4 $ 519.3
Gas 622.5 5.0 767.4 727.9
Other 233.7 1.8 258.7 124.8
- -------------------------------------------------------------------------------------
Total Regulated Businesses 1,472.8 11.7 1,583.5 1,372.0
- -------------------------------------------------------------------------------------
Aquila Energy 10,585.6 84.3 7,031.0 2,672.7
International and other 505.0 4.0 311.8 287.6
- -------------------------------------------------------------------------------------
TOTAL $ 12,563.4 100.0% $ 8,926.3 $ 4,332.3
- -------------------------------------------------------------------------------------
</TABLE>
56
<PAGE>
<TABLE>
Year Ended December 31,
---------------------------------------------
Dollars in millions 1998 1997 1996
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS BEFORE INTEREST AND TAXES:
Regulated Businesses $ 207.7 59.1% $ 197.5 $ 206.3
Aquila Energy (a) 54.1 15.4 82.4 90.2
International (b) 103.8 29.5 52.5 79.7
Corporate and other (14.2) (4.0) 26.7 (50.0)
- --------------------------------------------------------------------------------------------
TOTAL $ 351.4 100.0% $ 359.1 $ 326.2
- --------------------------------------------------------------------------------------------
</TABLE>
(a) THE AQUILA ENERGY SEGMENT INCLUDES EQUITY EARNINGS OF $34.5, $30.5 AND
$48.6 MILLION IN 1998, 1997 AND 1996, RESPECTIVELY.
(b) THE INTERNATIONAL SEGMENT INCLUDES OPERATING ACTIVITIES IN AUSTRALIA, NEW
ZEALAND, CANADA AND THE UNITED KINGDOM WHICH HAD TOTAL EQUITY EARNINGS OF
$88.5, $42.3 AND $60.1 MILLION IN 1998, 1997 AND 1996, RESPECTIVELY.
<TABLE>
Year Ended December 31,
------------------------------------------
Dollars in millions 1998 1997 1996
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
DEPRECIATION, DEPLETION AND AMORTIZATION:
Regulated Businesses $ 109.1 72.7% $ 84.9 $ 83.2
Aquila Energy 27.7 18.5 27.6 28.6
International 13.0 8.7 11.0 12.5
Corporate and other .2 .1 6.1 1.1
- ------------------------------------------------------------------------------------------------
TOTAL $ 150.0 100.0% $ 129.6 $ 125.4
- ------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
December 31,
------------------------------------------
Dollars in millions 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
IDENTIFIABLE ASSETS:
Regulated Businesses $ 2,040.9 34.1% $ 2,101.9
Aquila Energy 2,290.9 38.2 2,275.5
International 1,437.0 24.0 789.0
Corporate and other 222.7 3.7 (52.9)
- ---------------------------------------------------------------------------------
TOTAL $ 5,991.5 100.0% $ 5,113.5
- ---------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
Dollars in millions 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CAPITAL EXPENDITURES:
Regulated Businesses--
Electric $ 55.3 27.1% $ 57.4 $ 64.3
Gas 46.5 22.8 59.2 48.5
- --------------------------------------------------------------------------------
Total Regulated Businesses 101.8 49.9 116.6 112.8
- --------------------------------------------------------------------------------
Aquila Energy 33.8 16.5 28.4 26.4
International 20.0 9.8 19.4 21.5
Corporate and other 48.7 23.8 38.2 70.5
- --------------------------------------------------------------------------------
TOTAL $ 204.3 100.0% $ 202.6 $ 231.2
- --------------------------------------------------------------------------------
</TABLE>
57
<PAGE>
B. GEOGRAPHICAL INFORMATION
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------
Dollars in millions 1998 1997 1996
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
SALES:
United States $ 10,924.8 87.0% $ 8,007.8 $ 3,962.5
Canada (a) 1,222.4 9.7 704.4 180.9
United Kingdom 359.6 2.9 214.1 188.9
New Zealand 56.6 .4 -- --
- --------------------------------------------------------------------------------------------------
TOTAL $ 12,563.4 100.0% $ 8,926.3 $ 4,332.3
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Earnings Available for Common Shares:
United States $ 84.2 63.7% $ 105.2 $ 77.0
Canada (a) 6.7 5.1 10.8 9.5
Australia (b) 40.3 30.5 11.3 14.1
New Zealand 6.5 4.9 1.9 2.4
United Kingdom (5.5) (4.2) (7.4) .7
- --------------------------------------------------------------------------------------------------
TOTAL $ 132.2 100.0% $ 121.8 $ 103.7
- --------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
December 31,
-----------------------------------
Dollars in millions 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
IDENTIFIABLE ASSETS:
United States $ 4,336.5 72.4% $ 4,205.6
Canada (a) 439.9 7.3 376.4
Australia (b) 230.9 3.9 270.3
New Zealand 839.4 14.0 160.7
United Kingdom 144.8 2.4 100.5
- --------------------------------------------------------------------------------
TOTAL $ 5,991.5 100.0% $ 5,113.5
- --------------------------------------------------------------------------------
</TABLE>
(a) CANADIAN SALES, EARNINGS AVAILABLE FOR COMMON SHARES AND IDENTIFIABLE
ASSETS INCLUDE AQUILA ENERGY'S CANADIAN OPERATIONS AND VARIOUS SMALL
CANADIAN GAS MARKETING COMPANIES.
(b) EARNINGS AVAILABLE AND A MAJORITY OF THE IDENTIFIABLE ASSETS RELATE TO
EQUITY INVESTMENTS.
NOTE 17: MERGERS
ST. JOSEPH LIGHT & POWER COMPANY
(UNAUDITED)
On March 4, 1999, we agreed to merge with St. Joseph Light & Power Company
(SJL&P). Under the agreement, SJL&P shareholders will receive a fixed $23.00
per share for each SJL&P common share. This will be converted into UtiliCorp
common shares when the merger is completed. We expect to account for the
transaction as a pooling of interests, although that is not a condition of
the agreement. The merger is subject to approval by SJL&P shareholders and
state and federal regulatory agencies and is expected to close in mid-2000.
KANSAS CITY POWER & LIGHT COMPANY (KCPL)
In September 1996, KCPL terminated the Amended and Restated Agreement and
Plan of Merger (the Agreement) among KCPL, KC Merger Sub, Inc., UtiliCorp
United Inc. and KC United Corp., which would have provided for the merger of
UtiliCorp and KCPL.
Since KCPL's shareholders did not approve the merger under the terms of
the Agreement, KCPL was required to pay us $5.0 million. We received this
payment in September 1996. In connection with the Agreement termination, we
expensed deferred merger costs of about $11.0 million (pretax), net of the
termination fee payment.
In February 1997, Western Resources Inc. and KCPL signed a definitive
agreement to merge. As a result, KCPL paid us a $53.0 million breakup fee.
We recorded this merger termination fee in the first quarter of 1997.
58
<PAGE>
NOTE 18:
QUARTERLY FINANCIAL DATA (Unaudited)
Financial results for interim periods do not necessarily indicate trends for
any 12-month period. Quarterly results can be affected by the timing of
acquisitions, the effect of weather on sales, and other factors typical of
utility operations and energy related businesses.
<TABLE>
<CAPTION>
1998 QUARTERS (a) 1997 QUARTERS (a)
-------------------------------------------- -------------------------------------------
IN MILLIONS, EXCEPT PER SHARE FIRST SECOND THIRD FOURTH First Second Third Fourth
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Sales $ 2,895.9 $ 2,564.7 $3,808.8 $3,294.0 $ 2,059.6 $ 1,550.1 $ 2,256.5 $ 3,060.1
Gross profit 253.6 210.3 247.9 255.6 254.2 216.7 237.0 246.4
Earnings before extraordinary item
and cumulative effect of software
accounting change 43.3 23.4 28.5 37.0 57.9 20.3 24.9 31.0
Net income 43.3 23.4 28.5 37.0 50.7 20.3 24.9 26.2
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings per common share before
extraordinary item and cumulative
effect of software accounting change:
Basic (b)(c) $ .54 $ .29 $ .37 $ .45 $ .72 $ .25 $ .31 $ .39
Diluted (b) .53 .29 .36 .45 .71 .25 .31 .39
- ----------------------------------------------------------------------------------------------------------------------------------
Cash dividend per common share $ .30 $ .30 $ .30 $ .30 $ .29 $ .29 $ .29 $ .29
Market price per common share:
High $ 26.29 $ 26.33 $ 26.25 $ 24.46 $ 18.83 $ 19.59 $ 20.59 $ 26.04
Low 23.33 23.21 22.63 22.87 17.00 17.17 19.33 20.09
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) ALL PER SHARE AMOUNTS HAVE BEEN RESTATED FOR THE 3-FOR-2 STOCK SPLIT.
(b) RESTATED FOR ACCOUNTING CHANGE RELATED TO EARNINGS PER SHARE. SEE NOTE 1.
(c) THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS DIFFERS FROM THAT
REFLECTED IN NOTE 1 DUE TO THE WEIGHTING OF COMMON SHARES OUTSTANDING
DURING EACH OF THE RESPECTIVE PERIODS.
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59
<PAGE>
REPORT OF MANAGEMENT
The management of UtiliCorp United Inc. is responsible for the information
that appears in this annual report, including its accuracy. We prepared the
accompanying consolidated financial statements in accordance with generally
accepted accounting principles. In addition to selecting appropriate
accounting principles, we are responsible for the way information is
presented and for its reliability. To report financial results we must often
make estimates based on currently available information and judgements of
current conditions and circumstances.
We have set up well-developed systems of internal control to ensure the
integrity and objectivity of the consolidated financial information in this
report. These systems are designed to provide reasonable assurance that
UtiliCorp's assets are safeguarded and that the transactions are properly
authorized and recorded in accordance with the appropriate accounting
principles.
Through its Audit Committee, the Board of Directors participates in the
process of reporting financial information. The Audit Committee selects our
independent accountants. It also reviews, along with management, our
financial reporting and internal accounting controls, policies and practices.
/s/ Richard Green Jr.
Richard C. Green, Jr.
Chairman of the Board
and Chief Executive Officer
/s/ James S. Brook
James S. Brook
Vice President, Controller
and Chief Accounting 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 of UtiliCorp
United Inc. and subsidiaries at December 31, 1998 and 1997 and the related
consolidated statements of income, common shareowners' equity, comprehensive
income, and cash flows for each of the three years in the period ended
December 31, 1998. 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, 1998 and 1997 and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1998 in conformity with
generally accepted accounting principles.
As explained in Note 4 to the consolidated financial statements,
effective October 1 , 1997, the company changed its method of accounting for
internally developed software costs.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Kansas City, Missouri
February 1 , 1999
60
<PAGE>
EXHIBIT 21
UtiliCorp United, Inc.
Subsidiaries
1998 Annual Report on Form 10-K
SUBSIDIARY JURISDICTION OF INCORPORATION
---------- -----------------------------
West Kootenay Power, Ltd. Province of British Columbia
UtilCo Group, Inc. Delaware
Aquila Energy Corporation Delaware
UtiliCorp Asia Pacific Delaware
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
As Independent Public Accountants we hereby consent to the
incorporation by reference of our report dated February 1, 1999, appearing
on page 60 of the 1998 Annual Report to Shareholders, which is incorporated in
the Form 10-K, into the company's previously filed Registration Statements on
Form S-3 (Nos. 333-67067, 33-60406, 33-57167, and 33-39466) and on Form S-8
(Nos. 333-66233, 33-45525, 33-50260, 33-45074, 33-52094, and 333-19671). We
also consent to the incorporation of our report dated February 1, 1999, on
the Financial Statement Schedule, appearing on page 24 of the Form 10-K. It
should be noted that we have not audited any financial statements of
UtiliCorp United, Inc. subsequent to December 31, 1998 or performed any audit
procedures subsequent to the date of our reports.
/s/ ARTHUR ANDERSEN LLP
Kansas City, Missouri
March 25, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
1998 CONSOLIDATED FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 121
<SECURITIES> 0
<RECEIVABLES> 1,138
<ALLOWANCES> 0
<INVENTORY> 235
<CURRENT-ASSETS> 1,765
<PP&E> 3,314
<DEPRECIATION> 0
<TOTAL-ASSETS> 5,992
<CURRENT-LIABILITIES> 2,093
<BONDS> 1,476
0
0
<COMMON> 94
<OTHER-SE> 1,352
<TOTAL-LIABILITY-AND-EQUITY> 5,992
<SALES> 12,563
<TOTAL-REVENUES> 12,563
<CGS> 11,596
<TOTAL-COSTS> 727
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 133
<INCOME-PRETAX> 219
<INCOME-TAX> 87
<INCOME-CONTINUING> 132
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 132
<EPS-PRIMARY> 1.65
<EPS-DILUTED> 1.63
</TABLE>
