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FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 for the fiscal year ended August 31, 1998.
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from __________to__________
Commission file number 001-13643
ONEOK, INC.
(Exact name of registrant as specified in its charter)
OKLAHOMA 73-1520922
(State or other jurisdiction of (I.R.S. Employer
incorporation of organization) Identification No.)
100 WEST FIFTH STREET, TULSA, OK 74103
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (918) 588-7000
(Former name if changes since last report.)
Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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Common stock, with par value of $0.01 New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
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 Registration S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
Aggregate market value of registrant's voting stock held by nonaffiliates as of
August 31, 1998, was: Common stock of $949.3 million.
On August 31, 1998, the Company had 31,576,287 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
DOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement related to 1999 annual meeting. Part III
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ONEOK, INC.
1998 ANNUAL REPORT ON FORM 10-K
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PART I PAGE NO.
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Item 1. Business 1 - 11
Item 2. Properties 12 - 14
Item 3. Legal Proceedings 15 - 16
Item 4. Results of Votes of Security Holders 17
PART II
Item 5. Market Price and Dividends on the Registrant's
Common Stock and Related Shareholder Matters 18
Item 6. Selected Financial Data 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 19 - 31
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 31 - 32
Item 8. Financial Statements and Supplementary Data 33 - 56
Item 9. Changes in and Disagreements with Accountants
On Accounting and Financial Disclosures 57
PART III
Item 10. Directors, Executive Officers, Promoters, and
Control Persons of the Registrant 57
Item 11. Executive Compensation 57
Item 12. Security Ownership of Certain Beneficial Owners and Management 57
Item 13. Certain Relationships and Related Transactions 57
PART IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 58 - 60
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PART I.
ITEM 1. BUSINESS
GENERAL - ONEOK, Inc. (formerly WAI, Inc.), an Oklahoma corporation, was
organized on May 16, 1997. On November 26, 1997, it acquired the gas business of
Western Resources, Inc. (Western) (see Acquisitions and Mergers below) and
merged with ONEOK Inc., a Delaware corporation organized in 1933. It was a
successor to a company founded in 1906 as Oklahoma Natural Gas Company.
ONEOK, Inc. and subsidiaries (collectively, the Company) engage in several
aspects of the energy business providing environmentally clean fuels and
products. The Company purchases, gathers, compresses, transports, and stores
natural gas for distribution to consumers. It also transports gas and leases
pipeline capacity to others. The Company drills for and produces oil and gas,
extracts and sells natural gas liquids, and is engaged in the gas marketing
business. In addition, it leases and operates a headquarters office building
(leasing excess space to others) and owns and operates a related parking
facility. As a regulated natural gas utility, the Company distributes natural
gas to approximately 1.4 million customers in the states of Oklahoma and Kansas.
The Company's business units are characterized as operating within either a rate
regulated environment (regulated operations) or a nonregulated environment
(nonregulated operations).
The regulated business unit provides natural gas distribution, transportation,
gas supply, and storage services in Oklahoma and Kansas. The Company's
operations in Oklahoma are conducted through Oklahoma Natural Gas Company
Division, ONEOK Gas Transportation Company Division and three wholly-owned
subsidiaries, ONEOK Gas Transportation, L.L.C., ONG Transmission Company, and
ONG Sayre Storage Company, which together form an integrated intrastate natural
gas distribution and transmission business which serves residential, commercial,
and industrial customers in about 75 percent of the state of Oklahoma,. These
companies will be collectively referred to herein as ONG. The Company's
operations in Kansas are conducted through Kansas Gas Service Company Division
(Kansas Gas Service) and Mid Continent Market Center (MCMC), a wholly-owned
transportation company. These companies will be collectively referred to herein
as KGS. KGS's regulated gas operations are primarily engaged in distribution and
intrastate gas transportation, as well as gas wheeling, parking, balancing and
storage services. Kansas Gas Service serves residential, commercial, and
industrial customers in about 67 percent of Kansas. Kansas Gas Service also
conducts regulated gas distribution operations in northeastern Oklahoma.
The Oklahoma Corporation Commission recently promulgated rules to restructure
Oklahoma's natural gas utility industry which require gas utility companies to
"unbundle" their natural gas utility services in the State of Oklahoma. In
compliance with such rules, the Company filed an application to unbundle its
services upstream of the city gates of its distribution systems. On July 31,
1998, the Commission issued an interim Order separating ONG's utility services
into distribution, transportation, gas supply, storage, and gathering services.
The Order directed that services upstream of the city gate for distribution
systems (i.e., transportation, gas supply, storage and gathering services) be
obtained through a competitive bid process. The interim Order also established
the cost of service to be allocated to the various upstream services.
The nonregulated business unit includes the following core business segments:
natural gas marketing activities conducted primarily by ONEOK Gas Marketing
Company; gas processing and gas gathering activities conducted primarily by
ONEOK Gas Processing, L.L.C., and ONEOK Producer Services, L.L.C.; and
production activities conducted by ONEOK Resources Company. Other businesses
include ONEOK Leasing Company who leases and operates a headquarters building,
and ONEOK Parking Company, who owns and operates a parking garage. ONEOK Power
Marketing Company has been formed for the purpose of the wholesale marketing of
electricity but has not yet begun operations.
This Form 10-K (and certain other documents that are incorporated by reference
in this 10-K) contains statements concerning Company expectations or predictions
of the future that are "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995. These statements are intended
to be covered by the safe harbor provision of the Securities Act of 1933 and the
Securities Exchange Act of 1934. Forward-looking statements are based on
management's beliefs and assumptions based on information currently available.
It is important to note that actual
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results of Company earnings could differ materially from those projected in such
forward-looking statements. Factors that may impact forward-looking statements
include, but are not limited to, the following: (I) the effects of weather and
other natural phenomena; (ii) increased competition from other energy suppliers
as well as alternative forms of energy; (iii) the capital intensive nature of
the Company's business; (iv) economic climate and growth in the geographic areas
in which the Company does business; (v) the uncertainty of gas and oil reserve
estimates; (vi) the timing and extent of changes in commodity prices for natural
gas, electricity, and crude oil; (vii) the nature and projected profitability of
potential projects and other investments available to the Company; (viii)
conditions of capital markets and equity markets; (ix) Year 2000 issues, and (x)
the effects of changes in governmental policies and regulatory actions,
including income taxes, environmental compliance and authorized rates.
Accordingly, while the Company believes these forward- looking statements to be
reasonable, there can be no assurance that they will approximate actual
experience or that the expectations derived from them will be realized. When
used in Company documents, the words "anticipate," "expect," "projection,"
"goal" or similar words are intended to identify forward-looking statements. The
Company does not have any intention or obligation to update forward-looking
statements after they distribute this 10-K even if new information, future
events or other circumstances have made them incorrect or misleading.
ACQUISITIONS AND MERGERS - The following summarizes material acquisitions and
mergers completed in the current fiscal year; no material acquisitions took
place in the prior four years. On November 26, 1997, the Company acquired from
Western all of the assets of Western that were primarily used in, or primarily
related to or primarily generated by the field operations of the local natural
gas distribution business of Western, and all of the outstanding capital stock
of Western's directly or indirectly wholly-owned subsidiaries, Westar Gas
Marketing, Inc. and MCMC, and assumed (i) all of the liabilities of Western that
arose primarily out of or related primarily to or were primarily generated by
such gas business and (ii) approximately $161 million in aggregate principal
amount of debt of Western; and the Company merged (the "Merger") into ONEOK,
Inc., a Delaware corporation, with the Company as the surviving corporation. The
shares of ONEOK, Inc. common stock were converted on a one-for-one basis into
shares of stock of the Company, and Western received 2,996,702 shares of the
Company's Common Stock and 19,317,584 shares of the Company's Series A
Convertible Preferred Stock. Such shares and additional shares purchased by
Western at the Closing of the transaction represented in the aggregate 9.9
percent of the Common Stock and 45 percent of the Capital Stock of the Company.
A shareholder agreement, which includes standstill provisions, prevents Western
from increasing its position in the Company above a capital stock interest of 45
percent and maintains control of the Company in the hands of the public
shareholders of the Company. The transaction resulted in the acquisition of
660,000 new distribution customers, 10,068 miles of pipeline, two Kansas gas
processing plants with a 200 million cubic feet per day capacity, and a natural
gas marketing company with a retail market focus to the Company.
The acquisition was accounted for as a purchase and, accordingly, the operating
results of the properties acquired from Western are included in the
consolidated financial statements since December 1, 1997. The aggregate
purchase price was approximately $824 million, including debt assumed and
transaction costs. The aggregate purchase price, which was funded through the
issuance of a combination of preferred and common stock, was allocated based on
the estimated fair value of the net assets. The excess of the purchase price
over the fair value of the net assets acquired approximated $74 million and is
being amortized over 40 years.
From time to time, the Company has acquired and sold gas processing plant
properties, gathering and transportation facilities and other operating assets
in an effort to enhance overall operational efficiency, none of these
transactions have been material to the Company's financial position.
The Company's strategy is to acquire additional gas distribution and
transmission facilities, gas producing properties, or other assets which will
further enhance its existing operations and will continue to pursue such
opportunities in the future.
ENVIRONMENTAL MATTERS - In connection with the Western transaction, the Company
acquired 12 manufactured gas sites located in Kansas which may contain coal tar
and other potentially harmful materials that are classified as hazardous
material. Hazardous materials are subject to control or remediation under
various environmental laws and regulations. A consent agreement with the Kansas
Department of Health and Environment (KDHE) presently governs all future work at
these sites. The terms of the consent agreement allow the Company to investigate
these sites and set remediation priorities based upon the results of the
investigations and risk analysis. The prioritized sites will be investigated
over
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a ten year period. At August 31, 1998, the costs of the investigations and risk
analysis have been minimal. Limited information is available about the sites and
no testing has been performed. Management's best estimate of the cost of
remediation ranges from $100 thousand to $10 million per site based on a limited
comparison of costs incurred to remediate comparable sites. These estimates do
not give effect to potential insurance recoveries, recoveries through rates or
from third parties. The KCC has permitted others to recover their remediation
costs through rates. It should be noted that additional information and testing
could result in costs significantly below or in excess of the amounts estimated
above. To the extent that such remediation costs are not recovered, the costs
could be material to the Company's results of operations and cash flows
depending on the degree of remediation required and number of years over which
the remediation must be completed.
The Company's expenditures for environmental evaluation and remediation have not
been significant in relation to the results of operations of the Company.
Capital expenditures for environmental issues during the 1998 fiscal year
totaled $666,000. There have been no material effects upon earnings or the
Company's competitive position during the 1998 fiscal year related to compliance
with these regulations.
EMPLOYEES - The Company employed 3,211 persons at August 31, 1998. Nine
hundred-forty employees of KGS are subject to collective bargaining contracts.
The Company did not experience any strikes or work stoppages during 1998.
The Company's current contracts with the Unions are as follows:
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UNION EMPLOYEES CONTRACT EXPIRES
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United Steelworkers of America 533 June 6, 2002
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International Union of Operating Engineers 20 June 6, 2002
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Gas Workers Metal Trades of the United
Association of Journeymen and Apprentices of the
Plumbing and Pipefitting Industry of the United
States and Canada 13 June 6, 2002
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International Brotherhood of Electrical Workers 374 June 30, 1999
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FINANCIAL AND STATISTICAL INFORMATION - For financial and statistical
information regarding the Company's business units by segment, see "Management's
Discussion and Analysis of Financial Condition and Related Operations" and Note
K of Notes to Consolidated Financial Statements.
DESCRIPTION OF BUSINESS SEGMENTS
(A) REGULATED OPERATIONS
GENERAL
The Oklahoma operations comprise a fully integrated intrastate natural gas
gathering, storage, distribution and transportation business, which purchases,
stores, transports, and distributes natural gas for sale to wholesale and retail
customers located primarily in the state of Oklahoma. It also leases pipeline
capacity under its Pipeline Capacity Lease (PCL) program to large volume
commercial and industrial customers for their use in transporting natural gas to
their facilities. It transports gas for others under Section 311(a) of the
Natural Gas Policy Act (NGPA) of 1978. The operations are consolidated for
ratemaking purposes by the Oklahoma Corporation Commission (OCC).
ONG purchases natural gas from gas processing plants, producing gas wells, and
pipeline suppliers, and utilizes five underground storage facilities as
necessary to deliver natural gas to approximately 750,000 customers at August
31, 1998, located in 295 communities in Oklahoma. ONG's largest markets are the
Oklahoma City and Tulsa metropolitan areas. ONG also sells natural gas and/or
leases pipeline capacity to other local gas distributors serving 46 Oklahoma
communities. ONG serves an estimated population of over 2 million.
Five underground storage facilities are owned and capacity is leased to third
parties on a short-term basis. The Sayre gas storage facility is leased, on a
long-term basis, to and operated by the Natural Gas Pipeline Company of America.
Sayre retains capacity for its use.
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Kansas Gas Service supplies natural gas at retail to 362 communities in Kansas
and Oklahoma with approximately 96 percent of those gas deliveries to Kansas
customers. It also makes wholesale delivery to eight communities and two
utilities. The distribution system purchases natural gas from various suppliers
that is transported by intrastate and interstate pipeline companies. MCMC
provides Kansas Gas Service and others with natural gas transportation,
wheeling, parking, balancing, and storage services. Under a long term
arrangement, Kansas Gas Service provides and manages the field operations and
various administrative and general needs of MCMC. MCMC also transports gas for
its large commercial and industrial customers which purchase gas on the spot
market. KGS's largest markets served include Johnson County, Wichita, and
Topeka, Kansas, and Bartlesville, Oklahoma. Kansas Gas Service and MCMC are not
consolidated for ratemaking purposes by the Kansas Corporation Commission (KCC).
MCMC stores gas in two company-owned underground storage facilities, and
additional leased facilities, for delivery to customers during periods of higher
demand. A $10 million expansion project, to be completed in 2000, is expected to
increase the storage capacity from 4.6 to 6.3 Bcf.
Of the Company's consolidated revenues, revenues from regulated operations
represent approximately 53.0, 51.5, and 44.0 percent for 1998, 1997, and 1996,
respectively. Income before interest and income taxes from the regulated
operations is 73.4, 78.0, and 80.4 percent of the consolidated income before
interest and income taxes for 1998, 1997, and 1996, respectively.
GAS SUPPLY
Gas supplies available to ONG for purchase and resale include supplies of gas
under both short and long-term contracts with independent producers, as well as
pipeline companies, gas processors, and other suppliers that own or control
reserves. Oklahoma is the third largest gas producing state in the nation; and
ONG, unlike most utilities, has direct access through its transportation system
to all of the major gas producing areas in the state. The system, which
intersects with 10 interstate pipelines at 26 interconnect points, 38 gas
processing plants, and 128 producing fields located in Oklahoma, allows natural
gas to be moved to locations throughout the state and nation. In addition, four
of the storage facilities operated by ONG are located in close proximity to its
large market areas. These four storages have a combined average capacity of 119
billion cubic feet to help assure deliverability to customers even on winter
peak usage days. On such days, withdrawal from storage can provide as much as 50
percent of the system's needs. The record for all-time peak gas deliveries
through the system in a single day was 1.92 billion cubic feet.
The ONG rate schedule's "Order of Curtailment" and the KGS rate order's
"Priority of Service" provides for first reducing or totally discontinuing gas
service to the very large industrial users and graduating down to requesting
residential and commercial customers to reduce their gas requirements to an
amount essential for public health and safety.
KGS has transportation agreements for delivery of gas which have terms varying
in length from one to twenty years with the following non-affiliated pipeline
transmission companies: Williams Natural Gas Company ("WNG"), Kansas Pipeline
Partnership, Panhandle Eastern Pipeline Company, and various other intrastate
and interstate pipelines. Gas transported under these agreements represents
approximately 80 percent of the total distribution system throughput.
In October 1994, KGS executed a long-term gas purchase contract ("Base
Contract") and a peaking supply contract with Amoco Production Company ("Amoco")
for the purpose of meeting the requirements of the customers served over the WNG
pipeline system. KGS anticipates that the Base Contract will supply between 50
percent and 65 percent of KGS' demand served by the WNG pipeline system. Amoco
is one of various suppliers over the WNG pipeline system and if this contract
were canceled, management believes gas supplied by Amoco could be replaced with
gas from other suppliers. Gas available under the Base Contract is also
available for sale by KGS to other parties and sales are recorded as opportunity
gas sales.
The remaining 20 percent of Kansas Gas Service's total distribution throughput
is transported entirely through MCMC. The related natural gas is purchased from
a combination of direct wellhead production, from the outlet of natural gas
processing plants, and from natural gas marketers and production companies.
Kansas Gas Service retains a priority right to capacity on MCMC necessary to
serve its customers. KGS has the
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opportunity to negotiate for the purchase of natural gas with producers or
marketers utilizing MCMC services, which increases the potential supply.
To meet seasonal heating demands for residential and commercial customers, KGS
owns and operates and has under contract underground gas storage facilities.
Inventories of stored gas are typically near maximum level immediately prior to
the winter months and reduced as needed to meet system requirements.
The Company has a surplus of natural gas available to its utility systems and
does not anticipate problems with securing additional gas supply as needed for
its customers.
CUSTOMERS
RESIDENTIAL AND COMMERCIAL - ONG and KGS distribute natural gas as public
utilities to approximately 80 percent of Oklahoma and 67 percent of Kansas.
Natural gas sales to residential and commercial customers, which are used
primarily for heating and cooking, account for approximately 60 and 26 percent
of gas sales, respectively in Oklahoma and 73 and 26 percent of gas sales in
Kansas, respectively. Gas sales to residential and commercial customers are
seasonal, as a substantial portion of such sales are used principally for space
heating. Accordingly, the volume of gas sales is consistently higher during the
heating season (November through May) than in other months of the year. Rates
for natural gas distribution operations include a temperature normalization
adjustment clause during the heating season for ONG customers.
A franchise is a right to use the municipal streets, alleys, and other public
ways for utility facilities for a defined period of time for a fee. Although the
laws of the states of Oklahoma and Kansas prohibit exclusive utility franchises,
management nevertheless believes there are advantages to having franchises in
the larger municipalities in which operations are conducted. ONG has franchises
or gross receipts agreements in 234 municipalities while KGS holds franchises in
295 municipalities. In management's opinion, its franchises contain no unduly
burdensome restrictions and are sufficient for the transaction of business in
the manner in which it is now conducted.
INDUSTRIAL - A substantial portion of the ONG system throughput is transported
for industrial customers. Under the Company's PCL program, the customer, for a
fee, can have its gas, whether purchased from ONG or a third-party supplier,
transported to its facilities utilizing lines owned by ONG. PCL services are at
negotiated rates which are generally below the approved PCL tariff rates, and
competition continues to drive the rates lower. Industrial sales, rentals for
PCL's, and other energy-related operations tend to remain relatively constant
throughout the year, while interstate transportation volumes fluctuate based on
market demand. During the 1997 year, the Company was the successful bidder to
transport gas to four natural gas-fired electric generating plants owned by
Public Service Company of Oklahoma. No single customer accounted for more than
ten percent of consolidated operating revenues.
KGS industrial sales account for less than one percent of natural gas delivered.
KGS transports gas for its large industrial customers through it's End-Use
Customer Transportation (ECT) program. This program allows industrial customers
to purchase gas on the spot market and have it transported by KGS. KGS earned
approximately the same margin on the volume of gas transported as on volumes
sold except where discounting occurred in order to retain the customer's load.
No single customer accounted for more than ten percent of consolidated operating
revenues.
The potential impact of the loss of a significant portion of this volume is
discussed at Management's Discussion and Analysis of Financial Conditions and
Results of Operations, Liquidity, on page 30.
COMPETITION
The natural gas industry is expected to remain highly competitive. Management
believes that it must maintain a competitive advantage in order to retain its
customers and, accordingly, continues to focus on reducing costs and pursuing
unbundling opportunities.
The Company is subject to competition from electric utilities offering
electricity as a rival energy source and competing for the space heating, water
heating, and cooking markets. The principal means to compete against alternative
fuels is lower prices, and natural gas continues to maintain its price advantage
in the residential, commercial, and both small
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and large industrial markets. In residential markets, the average cost of gas is
less for ONG customers and for KGS customers than the average cost of gas
nationwide and considerably less than the cost of an equivalent amount of
electricity.
The Company is subject to competition from other pipelines for its existing
industrial load. The PCL program and Special Industrial Sales Program (SISP)
offered by ONG are a response to such competitive pressure. The PCL rate allows
ONG to effectively compete in these markets and maintain throughput and
therefore, load factors which benefit all customer classes. KGS, through the ECT
program, is able to compete with other pipelines and continue to serve its large
commercial and industrial customers. Competition, however, continues to compress
rates.
In April 1992, the Federal Energy Regulatory Commission (FERC) approved Order
636. Less than one percent of ONG's gas supply is transported on interstate
pipelines; 80 percent of KGS' gas supply is transported on interstate pipelines.
Increasing competition in the natural gas industry, along with the efforts of
the regulatory commissions, have been driving forces behind the Company's plans
to unbundle its services.
GOVERNMENT REGULATIONS
Rates charged for gas services, including distribution, transportation, and
storage, are established by the OCC for Oklahoma Natural Gas and by the KCC and
OCC for Kansas Gas Service. Changes in the gas purchase costs are included in
the purchased gas adjustment clause. Other costs must be recovered through
periodic rate adjustments approved by the OCC and KCC.
The KCC has approved a pilot program KGS designed to moderate the cost its
customers pay for natural gas in cold weather months. Under this program, which
begins this heating season, the Company will use commodity derivative
instruments to cap the price of its anticipated winter heating season gas
purchases in order to protect customers from the upward volatility during the
winter heating months.
In August 1998, the KCC approved a pilot program in Kansas that will offer
residential customers the option of paying a fixed monthly bill. The program
will allow a qualified residential customer the option of paying a fixed monthly
amount based on the projected average annual usage rather than actual usage. A
similar program is in effect for customers in Oklahoma.
The OCC issued an interim order on July 31, 1998, for ONG to proceed with a
competitive bidding process to obtain some of the upstream services, such as
supply, transportation, and storage, necessary to serve the Oklahoma City and
Tulsa markets. The order outlines how ONG is to proceed with upstream
unbundling. While the Company supports the concept of unbundling, it believes
the order contains elements that are an "invasion of internal management
discretion" and has filed an appeal with the Oklahoma Supreme Court. The
ultimate outcome of these proceedings and their impact, if any, on future
earnings and cash flow can not be predicted at this time. See Item 3, Legal
Proceedings.
In a first step toward unbundling in Kansas, KGS filed a proposed tariff change
with the KCC, reducing the minimum requirement for transportation service to
3,000 Mcf annually and requested approval of a revenue-neutral residential basic
service charge and upstream capacity charge. Approval of this filing by the KCC
will allow KGS to expand transportation services to an additional 650 commercial
and industrial customers and to restructure residential customer bills to better
reflect the differences between the basic service charge for delivery and the
cost of natural gas.
A temperature adjustment clause, in effect for ONG customers since 1995, reduces
the effect of extremes in weather for both the Company and the customer. In
connection with the Western alliance, ONG filed a stipulation which included an
agreement not to file for a general rate increase for a period of one year. KGS
filed a stipulation which included an agreement not to file a general rate
increase for three years.
The Company has settled all known claims arising out of long-term gas supply
contracts containing "take-or-pay"
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provisions which purport to require the Company to pay for volumes of natural
gas contracted for but not taken. The OCC has authorized recovery of the
accumulated settlement costs over a 20 year period or approximately $6.7 million
annually through a combination of a surcharge from customers and revenue from
transportation under Section 311(a) of the NGPA and other intrastate
transportation revenues. There are no significant potential claims or cases
pending against the Company under remaining gas purchase contracts.
OTHER REGULATED BUSINESSES
OkTex Pipeline Company transports gas in interstate commerce under Section
311(a) of the NGPA and is treated as a separate entity by FERC. The Company has
the capacity to move up to 200 million cubic feet per day into the Lone Star Gas
Company's system in Texas and the Red River Pipeline. OkTex has complied with
the requirements of Order 636.
(B) NONREGULATED OPERATIONS
MARKETING
GENERAL - The Company purchases and markets natural gas, primarily in the
mid-continent area of the United States. The alliance with Western has expanded
the Company's operations to include retail customers. Due to expanded supply and
storage capabilities, the marketing operation has evolved from an intrastate
aggregator into an interstate aggregator. Of the Company's consolidated
revenues, revenues from the gas marketing operations represent approximately
40.7, 39.6, and 48.9 percent for 1998, 1997, and 1996, respectively. Income
before interest and income taxes from the marketing operation is 6.1, 6.1, and
10.7 percent of the consolidated income before interest and income taxes for
1998, 1997, and 1996, respectively.
MARKET CONDITIONS - The baseload marketing business is very competitive and, as
the industry matures, continues to go through a period of consolidation and
reduced margins. The Company's strategy is to concentrate its efforts on
capitalizing on day-to-day pricing volatility through the use of gas storage
facilities, hedging, and transportation arbitraging. Management believes that
its location in Oklahoma, its expansion into the Kansas market, as well as the
benefits derived from vertically integrating the gas marketing operations with
the Company's production, gathering, processing, storage, and transportation
businesses, will provide the strategic advantage necessary to compete.
NEW PRODUCTS AND SERVICES - In 1997, the marketing operation was the successful
bidder to provide firm and interruptible gas service to four natural gas-fired
electric generating plants owned by Public Service Company of Oklahoma.
The Company has received approval from FERC to market electricity. It is not
anticipated that these activities will be a major contributor to earnings in
fiscal 1999.
PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising from
fluctuations in both the market price and transportation costs of natural gas,
the Company routinely enters into natural gas futures, swaps, and options as a
method of protecting its margins on the underlying physical transactions.
However, net open positions in terms of price, volume, and specified delivery
point do occur.
GATHERING AND PROCESSING
GENERAL - The Company owns and operates one gas processing plant and has
nonoperating interests in three gas processing plants. The gas processing
operations include the extraction of natural gas liquids (NGL's) and the
separation ("fractionation") of mixed NGLs into component products (e.g.,
ethane/propane mix, propane, iso and normal butane, and natural gasoline). The
component products are used for petrochemical feedstock, residential heating and
cooking in rural areas, and blending into motor fuels. The industry as a whole
operates substantial numbers of such plants, many owned by large integrated oil
and gas companies and independents. NGL margins have been highly volatile over
the past several years as profitability is dependent on the relationship between
natural gas costs and NGL prices.
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Management believes that the industry is becoming much more competitive as
demand increases for NGLs, especially petrochemical feedstock.
Extraction is the process of removing NGLs from the inlet raw gas stream,
thereby reducing the Btu content and volume (referred to as "shrinkage"). In
addition, some gas from the gas stream is consumed as fuel during the
processing. The production costs of such liquids generally depend on the cost of
natural gas being processed and the underlying agreements. The Company has
compensated its gas suppliers for fuel and shrinkage costs in one of two ways,
either by returning a percentage of the proceeds from the extracted NGLs to the
supplier (a "percent of proceeds" contract) or by replacing an equivalent amount
of gas (a "fuel and shrink" contract). Due to the volatility of the natural gas
and NGL prices, "percent of proceeds" contracts generally provide a more stable
cash flow.
Of the Company's consolidated revenues, revenues from the gathering and
processing operations represent approximately 4.3, 6.2, and 4.8 percent for
1998, 1997, and 1996, respectively. Income before interest and income taxes
from the gathering and processing operation is 15.2, 10.0, and 7.4 percent of
the consolidated income before interest and income taxes for 1998, 1997, and
1996, respectively.
PROPERTY ACQUISITIONS AND SALES - The Company sold its interest in 11 gas
processing plants located in Western Oklahoma on February 1, 1998. The lack of
ownership of the gathering systems behind these plants was the primary
motivation for the sale. In a separate transaction, the Company sold its
minority ownership in the Laverne Gas Processing Plant. The sale of the
Company's interest in the 12 gas processing plants during fiscal 1998 eliminated
the Company's interest in "fuel-and-shrink" plants, which are subject to
volatile swings in profitability.
As part of the alliance with Western Resources the Company acquired the Minneola
Gas Processing Plant located in Ford County, Kansas, and increased its ownership
in the Indian Basin Plant to 42 percent.
The Company purchased an additional 55 percent interest in the Sycamore Gas
Gathering System on May 29, 1998. The purchase gives the Company a 97 percent
interest in the system and control over the company-owned production in that
area.
PRODUCTION
GENERAL - The Company's strategy is to concentrate ownership of natural gas and
oil reserves in its service territory in order to add value not only to its
existing production operations but also to integrate it into its processing,
marketing, transmission, gathering, and storage business. As a result, the
Company is focusing its efforts on acquisitions and exploitation activities.
Of the Company's consolidated revenues, revenues from the production operations
represent approximately 1.7, 2.3, and 2.1 percent for 1998, 1997, and 1996,
respectively. Income before interest and income taxes from the production
operation is 5.4, 6.8, and 2.3 percent of the consolidated income
before interest and income taxes for 1998, 1997, and 1996, respectively.
PRODUCING RESERVES - Natural gas is the primary focus of the Company's
production activities. As of August 31, 1998, the Company had a working interest
in 1,242 gas wells and 328 oil wells located primarily in Oklahoma, Kansas,
Texas, and Louisiana. A number of these wells produce from multiple zones.
MARKET CONDITIONS - The goal of the Company is to develop an economically viable
reserve base through acquisition and development. Additionally, the Company
plans to become even more active as an operator of the reserve base, which it
controls. In doing so, the Company competes with many large integrated oil and
gas companies and numerous independent oil and gas companies of various size.
The Company, as an industry standard, monitors well head prices on a daily basis
and, on occasion, has curtailed some of its natural gas production due to low
well head prices . Most production is sold to third party marketers, including
ONEOK Gas Marketing Company, at spot-market prices.
PROPERTY ACQUISITIONS AND SALES - The Company purchased gas and oil reserves
located in Oklahoma and Kansas from
10
<PAGE> 11
OXY USA, Inc. during the third quarter of 1998. The $128 million purchase
includes 400 wells producing approximately 30 million cubic feet of gas per day
and 400 barrels of oil per day and a gas sweetening plant. Based on estimated
reserves, this transaction almost doubled the Company's oil and gas reserves and
provided the Company with additional reserves located in Kansas.
On June 2, 1998, the Company acquired a 40 percent equity interest in K. Stewart
Petroleum Corp., an Oklahoma City based independent oil and gas producer. This
acquisition creates increased opportunities for the Company to expand its oil
and gas reserves in the Anadarko Basin, one of North America's most prolific gas
fields. K. Stewart Petroleum Corp. has been successful in applying new
exploration and drilling technologies including 3-D seismic, directional
drilling, magnetic resonance imaging, and advanced completion and stimulation
techniques. Gross cumulative discoveries by K. Stewart through December 31,
1997, exceed 100 billion cubic feet equivalent (Bcfe). This transaction also
gives the Company first look at all project development by K. Stewart with the
option to participate at the most favorable industry rate.
The acquisition of Washita Production Company, a Tulsa based independent oil and
gas producer, was closed in December 1997. The acquisition of Washita, valued at
approximately $20 million, was made with a combination of cash and ONEOK, Inc.
common stock. The transaction included 235 producing wells and significant
behind pipe and development drilling opportunities with proven reserves of
approximately 23 Bcfe. The wells are primarily located in the Anadarko and
Arkoma Basin of Oklahoma and include some properties in the Hugoton Basin of
Kansas.
During 1997, the Company purchased PSEC, Inc., an independent oil and gas
company in Oklahoma. The transaction included 180 wells with proven reserves of
20 Bcf of natural gas and 167,000 barrels of oil. Included in the transaction
was PSPC, Ltd., which operates and holds a 42 percent interest in the Sycamore
Gas Gathering System. The purchase was financed with $9.3 million long-term debt
and 334,252 shares of ONEOK Inc. common stock.
During 1996, the Company purchased substantially all of the Oklahoma oil and
natural gas properties of SCANA Petroleum Resources, Inc. The $43.1 million
purchase included over 500 producing properties of which 90 percent are natural
gas. Also in 1996, the Company sold all of its oil and gas properties in Alabama
and Mississippi for approximately $18.9 million.
These acquisitions and sales contribute to the Company's long-term strategy of
focusing on natural gas reserves in Oklahoma and Kansas to add value to all of
the Company's gas-related operations.
RISK MANAGEMENT - The Company's production segment continues to utilize
derivatives in order to hedge anticipated sales of oil and natural gas
production. These anticipated transactions have been hedged with commodity swaps
agreements whereby the Company is able to set the price to be received for the
future production and thus reduce the risk of declining market prices between
the origination date of the swap and the month of production. The Company's
strategy in hedging anticipated transactions is to eliminate the variability in
earnings of its production segment as a result of market fluctuations. To the
extent that management does not terminate a hedge or enter into an opposing
derivative, the current strategy will limit the potential gains which could
result from increases in market prices above the level set by the hedge.
OTHER BUSINESSES
The Company, through two subsidiaries, owns a parking garage and leases an
office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, in which the
Company's headquarters are located. The parking garage is owned and operated by
ONEOK Parking Company. ONEOK Leasing Company leases excess office space to
others. Almost all downtown Tulsa Class A office space is rented and very little
Class A office space is available city-wide. As a result, Class A rental rates
are increasing.
11
<PAGE> 12
ITEM 2. PROPERTIES
(A) DESCRIPTION OF PROPERTY
REGULATED
DISTRIBUTION - The Company owned 15,023 miles of pipeline and other distribution
facilities in Oklahoma and 10,068 miles of pipeline and other distribution
facilities in Kansas at August 31, 1998. The Company owns a five-story office
building in Oklahoma City, Oklahoma, as well as a number of warehouses, garages,
meter and regulator houses, service buildings, and other buildings throughout
Oklahoma and Kansas. The Company also owns a fleet of vehicles used primarily in
Oklahoma and maintains an inventory of spare parts, equipment, and supplies. It
leases substantially all of its vehicles operated in Kansas. In addition, the
Company owns five underground storage facilities located throughout Oklahoma and
two storage facilities in Kansas. Four of the Oklahoma storage facilities are
located in close proximity to its large market areas; the other storage facility
is located in western Oklahoma and is leased to and operated by another company.
However, 21.4 billion cubic feet of storage capacity in that facility has been
retained for use by the Company.
TRANSMISSION - The Company owned a combined total of 3,753 miles of transmission
and gathering pipeline in Oklahoma and 1,613 miles in Kansas at August 31, 1998.
Compression and dehydration facilities are located at various points throughout
the pipeline system.
PRODUCTION
The Company owns varying economic interests, including overriding royalty
interests, in 1,372 gas wells and 342 oil wells, some of which are multiple
completions. Such interests are in wells located primarily in Oklahoma, Kansas,
and Louisiana. The Company owns 152,652 net onshore developed leasehold acres
and 18,275 net onshore undeveloped acres, located primarily in Oklahoma, Kansas,
Texas, and Louisiana. The Company owns no offshore acreage.
Lease acreage in producing units is held by production. Leases not held by
production are generally for a term of three years and may require payment of
annual rentals.
GATHERING AND PROCESSING
The Company owns interests in four gas processing plants which extract liquid
hydrocarbons from natural gas. Two are located in Oklahoma, one in Kansas and
one in New Mexico. The Company's share of the total plant capacity of 379.5
million cubic feet per day is 152.7 million cubic feet per day. The Company owns
approximately a 97 percent interest in the Sycamore Gas Gathering System in
Carter County, Oklahoma and interests in various other gas gathering systems.
OTHER
The Company owns a parking garage and land, subject to a long-term ground lease
expiring in year 2009 with six five-year extensions available, upon which has
been constructed a seventeen-story office building with approximately 517,000
square feet of net rentable space. The office building is being leased to the
Company at a lease term of 25 years with six five-year renewal options. After
any renewal period, the Company can purchase the property at its fair market
value. The Company has occupied and reserved approximately 229,623 square feet
for its own use and leases the remaining space to others.
(B) OTHER INFORMATION
Oil and gas production is defined by the Securities and Exchange Commission
(SEC) to include natural gas liquids in their natural state. The Company's
processing operations produces natural gas liquids as a result of ownership in
four gas processing plants, but the Company does not own the reserves
attributable to the gas processed by these plants. The SEC excludes the
production of natural gas liquids resulting from the operations of gas
processing plants as an oil and
12
<PAGE> 13
gas activity. Accordingly, the following tables exclude information concerning
the production of natural gas liquids by the Company's processing operations.
OIL AND GAS RESERVES
All of the oil and gas reserves are located in the United States.
QUANTITIES OF OIL AND GAS RESERVES - See Note Q of Notes to Consolidated
Financial Statements on page 55.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES - See Note R of Notes to
Consolidated Financial Statements on page 55.
RESERVE ESTIMATES FILED WITH OTHERS
None.
QUANTITIES OF OIL AND GAS PRODUCED
The net quantities of oil and natural gas produced and sold, including
intercompany transactions, were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------
SALES 1998 1997 1996
- --------------------------------------------
<S> <C> <C> <C>
Oil (MBbls) 330 336 435
Gas (MMcf) 16,818 14,565 9,406
============================================
</TABLE>
AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS
Average sales prices and lifting costs are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------
<S> <C> <C> <C>
Average Sales Price (a)
Per Bbl of oil $15.70 $19.84 $17.73
Per Mcf of gas $2.21 $2.16 $1.86
Average Production Costs
Per Mcfe (b) $0.50 $0.48 $0.46
========================================================
</TABLE>
(a) In determining the average sales price of oil and gas, sales to affiliated
companies were recorded on the same basis as sales to unaffiliated customers.
(b) For the purpose of calculating the average production costs per Mcf
equivalent, barrels of oil were converted to Mcf using six Mcf of natural gas to
one barrel of oil. Production costs do not include depreciation or depletion.
WELLS AND DEVELOPED ACREAGE
The table shows gross and net wells in which the Company has a working interest
at August 31, 1998.
<TABLE>
<CAPTION>
- ---------------------------------
Gas Oil
- ---------------------------------
<S> <C> <C>
Gross wells 1,242 328
Net wells 431 154
=================================
</TABLE>
13
<PAGE> 14
Gross developed acres and net developed acres by well classification are not
available. Net developed acres for both oil and gas is 152,652 acres.
<TABLE>
<CAPTION>
- ---------------------------------
Gross Net
- ---------------------------------
<S> <C> <C>
Oklahoma 68,033 17,136
Texas 5,627 906
Louisiana 1,110 210
Alabama 77 23
=================================
</TABLE>
UNDEVELOPED ACREAGE
The gross and net undeveloped leasehold acreage at the end of the fiscal year is
as follows:
Of the net undeveloped acres, approximately 7 percent lies in the Ardmore Basin
area, 36 percent in the Anadarko Basin area in Oklahoma, 19 percent in the
Oklahoma portion of the Arkoma Basin, and 1 percent in the Texas Gulf Coast
area.
NET DEVELOPMENT WELLS DRILLED
The net interest in total development wells drilled, by well classification, is
as follows:
<TABLE>
<CAPTION>
- --------------------------
Development
- --------------------------
<S> <C>
1998
Productive 14.0
Dry 0.6
- --------------------------
Total 14.6
- --------------------------
1997
Productive 3.8
Dry 1.5
- --------------------------
Total 5.3
- --------------------------
1996
Productive 2.7
Dry 1.8
- --------------------------
Total 4.5
==========================
</TABLE>
PRESENT DRILLING ACTIVITIES
On August 31, 1998, the Company was participating in the drilling of 21 wells.
The Company's net interest in these wells amounts to 9.22 wells.
FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS
None.
14
<PAGE> 15
ITEM 3. LEGAL PROCEEDINGS
JOINT APPLICATION OF OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK, INC.,
ONEOK GAS TRANSPORTATION COMPANY, A DIVISION OF ONEOK, INC., AND KANSAS GAS
SERVICE COMPANY, A DIVISION OF ONEOK, INC., FOR APPROVAL OF THEIR UNBUNDLING
PLAN FOR NATURAL GAS SERVICES UPSTREAM OF THE CITY GATES OR AGGREGATION POINTS,
Cause PUD No. 980000177, before the Oklahoma Corporation Commission. On April 1,
1998, a Joint Application was filed to unbundle natural gas services upstream of
the citygate. As part of the Joint Application (as required by the Commission's
new unbundling rules) a proposal was submitted which would enable the Applicants
to commence competitively-bid service to the Tulsa and Oklahoma City aggregation
areas no later than November 1, 1998. Kansas Gas Service Company requested a
waiver from having to file an unbundling plan pending consolidation of its rates
with those of Oklahoma Natural Gas Company which was granted in the Amended
Order (see below). The Applicants filed direct testimony on April 17, 1998 and
certain intervenors filed responsive testimony and statements of position on
June 1, 1998. Hearings were held beginning July 6, 1998 and continued through
July 16, 1998. The Commission entered its Order on July 31, 1998 unbundling
utility services by separating distribution, transportation, gas supply, storage
and gathering services and directing that services upstream of the citygates be
obtained through competitive bidding. The Company was directed to request
competitive bids for upstream services for the Oklahoma City and Tulsa
aggregation areas commencing November 1, 1998, and for the remaining cities and
towns as scheduled in the Order. The Order also established the cost of service
for Oklahoma Natural Gas Company ("ONG") and ONEOK Gas Transportation Company
under which future rates will be determined and tariffs filed. On August 6,
1998, a Petition-in-Error was filed with the Oklahoma Supreme Court appealing
the Order of the Commission and a Notice of Appeal and Motion to Stay the Order
was filed with the Commission. Hearings were held on such Motion and a Motion to
Reconsider by one of the intervenors and the Commission took the matters under
advisement. The Appeal claims the Commission lacked jurisdiction and authority
to promulgate its unbundling rules and the Order exceeded its authority. The
Commission filed an Amended Order on August 20, 1998. The Company's position is
that the Amended Order is invalid due to the pending appeal of the original
Order. On August 17, 1998, the Commission filed a Motion to Dismiss the
Company's appeal. The Company filed its response on September 1, 1998. On
September 8, 1998, the Company filed a petition-in- error with the Oklahoma
Supreme Court appealing the amended order.
IN THE MATTER OF COMMISSIONER BOB ANTHONY'S INSPECTION OF THE BOOKS AND RECORDS
OF ANY PUBLIC SERVICE CORPORATION AND EXAMINATION, UNDER OATH, OF ANY OFFICER,
AGENT OR EMPLOYEE OF SUCH, IN RELATION TO THE BUSINESS AND AFFAIRS OF ARKANSAS
LOUISIANA GAS COMPANY, A DIVISION OF NORAM ENERGY CORP. AND OKLAHOMA NATURAL GAS
COMPANY, A DIVISION OF ONEOK INC. PURSUANT TO OKLAHOMA CONSTITUTION ARTICLE 9,
SECTIONS 18, 28 AND 34, Cause No. PUD 960000039 and related dockets (PUD 86-85,
96-100, 96-186), Oklahoma Corporation Commission. Commissioner Anthony filed
notice on February 13, 1996, and thereafter sought, in his capacity as an
individual Commissioner, to investigate transactions between the Company and
another entities in connection with the 1993 settlement of a long-running gas
contract dispute between the Company and one of its gas suppliers, Creek
Systems. The principal subject of the inquiry was a new gas supply arrangement
entered into in connection with the settlement between the Company and an entity
called Dynamic Energy Resources, which in turn assigned its interest in the
contract to two other unrelated companies. Commissioner Anthony contended that
he was questioning whether the new gas supply arrangement entered into as a
result of the settlement had resulted in excessive gas costs to the Company's
customers. The gas supply contracts in question had been examined in earlier
audits by the Commission staff and no improper costs or other improprieties had
been found. After extensive Commission proceedings and an original action in the
Oklahoma Supreme Court challenging Anthony's authority to conduct such an
individual investigation, a compromise was reached among all interested parties
(other than Commissioner Anthony) pursuant to which another Commission staff
investigation of the matter was conducted with full cooperation by the Company.
The staff again found no improper costs or other improprieties. On August 14,
1997, Commissioner Anthony filed a document prepared by a member of his staff
again claiming overpayment for gas supplied under the contract. No further
action has been taken by the Commission, however, as a result of the Report, an
Application of Michael Edward McAdams and John Powell Walker For Relief for
Improper and Excessive Costs, Cause No. PUD 98000188 was filed on April 6, 1998
against the Company seeking a review of the gas purchase agreement between the
Company and Dynamic Energy Resources. On April 29, 1998, ONG filed a motion to
dismiss which was denied by the Administrative Law Judge on September 1, 1998.
ONG appealed the Administrative Law Judge's Order to the Commission en banc on
September 11, 1998.
FENT, ET UX V. OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK INC., ET AL.,
No. CJ-88-10148, District Court,
15
<PAGE> 16
Oklahoma County. On October 6, 1988, the Plaintiffs filed a petition for
reimbursement for the cost of replacement of a yard line and for repairing the
gap in piping caused by the relocation of the meter to the property line and as
a class action for similarly situated customers. The Company moved to dismiss
the action on the grounds the District Court did not have subject matter
jurisdiction and a failure to state a cause of action for which relief could be
granted. The District Court granted the motion to dismiss and the Plaintiffs
appealed the decision. On August 14, 1991, the Court of Appeals reversed the
trial court's decision and remanded the case for further proceedings. The
appellate court held that the trial court had erred in ruling both that it was
without jurisdiction and that the Plaintiffs had failed to state a cause of
action, instead finding that under Commission Rule 6(a) the Company could be
responsible for maintenance of the gas line up to the outflow side of the meter.
As a result, the Company could have a duty to repair the gap caused by removal
of the meter and to maintain and repair the yard line. The case was remanded to
the District Court, the Company filed a related proceeding with the Oklahoma
Corporation Commission seeking an interpretation of the applicable Commission
rules, and although the Plaintiffs filed a motion in District Court to certify
the class, further proceedings in the case were stayed pending resolution of the
appeal of the decision in the related Corporation Commission proceeding. The
Corporation Commission ruled that ONG was not responsible for non-Fent yard
lines. Plaintiffs filed a motion to lift the stay which was granted by the
Court, enabling the case to proceed with discovery on the issue of whether
claims should be certified as a class action and Plaintiffs' allowed to act as
class representatives. The Company filed a motion to strike on the basis of the
Oklahoma Corporation Commission decision in that had determined that the Company
was not responsible for non-Fent yardlines, which was granted on July 26, 1996.
Fent appealed the decision of the District Court and on April 8, 1997, the
appeal was assigned to Division 2 of the Court of Appeals. On December 16, 1997,
the Court of Appeals decided in favor of the Company, upholding the trial
court's denial of class certification. Fent filed a Petition for Rehearing on
January 5, 1998. The Petition was denied on February 17, 1998. Fent then filed a
Petition for Writ of Certiorari with the Supreme Court on March 5, 1998. The
Supreme Court granted Certiorari on April 20, 1998. The Company filed a Request
to File Supplemental Briefs on April 30, 1998, which is still pending.
UNITED STATES OF AMERICA, EX REL. JACK GRYNBERG V. ALASKA PIPELINE CO., ET AL.,
(INCLUDING ONEOK, INC.), No. 95-725, in the United States District Court for the
District of Columbia. This is a qui tam action that was commenced on April 17,
1995 (but not served on ONEOK, Inc. until July 24, 1996), by the plaintiff
relator, Jack J. Grynberg ("Grynberg"), on behalf of the United States pursuant
to the False Claims Act, 31 U.S.C. ss. 3729, et seq., to recover the
underpayment of royalties on federally owned or Indian properties from 70 named
pipeline companies, including ONEOK, Inc. Grynberg claims that the named
pipeline companies have underpaid royalties to the United States as a result of
the improper measurement of the heating content and volume of natural gas which
they purchased from the federally owned or Indian lands. On behalf of the United
States, Grynberg seeks to recover the proceeds for the underpayment of
royalties, interest, treble damages, civil penalties of $5,000 to $10,000 for
each violation by a defendant pipeline company of the False Claims Act, and an
order requiring the defendant pipeline companies to discontinue the improper
practices. Grynberg also seeks to recover his expenses incurred in bringing the
action, plus attorneys' fees and costs. The Company, through its division ONEOK
Gas Transportation Company, joined a group of 53 defendants (the "Combined
Defendants") employing the law firm of Skadden, Arps, Slate, Meagher and Flom
LLP ("Skadden, Arps") and sharing their expense in addressing the defenses
against the action which are common to the group. Skadden, Arps filed on behalf
of the Combined Defendants a motion to dismiss the Second Amended Complaint on
several grounds (e.g., failure to state of claim, failure to plead fraud with
specificity, misjoinder of parties, improper venue, etc.). The court granted the
motion to dismiss on March 27, 1997, finding that there had been an improper
joinder of the defendants and that Grynberg had failed to state a claim with
particularity against each of the defendants. On May 15, 1998, Grynberg appealed
the decision to the District of Columbia Court of Appeals. Motions to dismiss
the action were filed in July, 1998 and the decision of the Court is pending.
The Company has been recently contacted by the Civil Division of the Commercial
Litigation Branch of the United States Department of Justice asking it to
comment on a separate lawsuit filed by Grynberg against ONEOK, Inc., ONEOK
Resources Company, and Oklahoma Natural Gas Company, in which the same
allegations and claims are made. The Company is preparing a response to the
Department of Justice.
The Company is a party to other litigation matters and claims which are normal
in the course of its operations, and while the results of litigation and claims
cannot be predicted with certainty, management believes the final outcome of
such matters will not have a materially adverse effect on consolidated results
of operations, financial position, or liquidity.
16
<PAGE> 17
ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS
(A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of the fiscal year covered by
this report to a vote of the Company's security holders, through the
solicitation of proxies or otherwise.
(B) EXECUTIVE OFFICERS OF THE REGISTRANT
All executive officers are elected at the annual meeting of directors and
serve for a period of one year or until their successors are duly elected.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
PERIOD SERVED BUSINESS EXPERIENCE
NAME AND POSITION AGE IN SUCH CAPACITY IN PAST FIVE YEARS
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
LARRY W. BRUMMETT 48 1997 to present Chairman of the Board of Directors and Chief Executive Officer
Chairman of the Board 1994 to 1997 Chairman of the Board of Directors, President, and Chief
and Chief Executive Officer Executive Officer
1993 to 1994 Executive Vice President of Oklahoma Natural Gas Company
- -----------------------------------------------------------------------------------------------------------------------------------
DAVID L. KYLE 46 1997 to present President and Chief Operating Officer
President of ONEOK 1995 to present Member of the Board of Directors
and Chief Operating Officer 1994 to 1997 President and Chief Operating Officer of Oklahoma Natural Gas Company
1993 to 1994 Executive Vice President of Oklahoma Natural Gas Company
- -----------------------------------------------------------------------------------------------------------------------------------
JOHN A. GABERINO, JR. 57 1998 to present Senior Vice President and General Counsel
Senior Vice President and 1993 to 1998 Stockholder, Officer and Director of Gable Gotwals Mock Schwabe
General Council Kihle Gaberino and predecessor firms
- -----------------------------------------------------------------------------------------------------------------------------------
JERRY D. NEAL 59 1993 to present Vice President, Treasurer, and Chief Financial Officer (Principal Financial
Vice President, Treasurer, and Accounting Officer)
and Chief Financial Officer
(Principal Financial and
Accounting Officer)
- -----------------------------------------------------------------------------------------------------------------------------------
BARRY D. EPPERSON 53 1997 to present Vice President, Controller, and Chief Accounting Officer
Vice President, Controller, 1993 to 1997 Vice President-Accounting of Oklahoma Natural Gas Company
and Chief Accounting Officer
- -----------------------------------------------------------------------------------------------------------------------------------
EUGENE N. DUBAY 49 1997 to present President and Chief Operating Officer of Kansas Gas Service Company
President and Chief Operating 1996 to 1997 Vice President of Corporate Development
Officer - Kansas Gas Service 1993 to 1995 Executive Vice President and Chief Operating Officer of Missouri
Company Gas Energy
- -----------------------------------------------------------------------------------------------------------------------------------
JAMES C. KNEALE 47 1997 to present President and Chief Operating Officer of Oklahoma Natural Gas Company
President and Chief Operating 1996 to 1997 Vice President of ONEOK Resources Company
Officer-Oklahoma Natural Gas 1995 to 1996 Vice President-Tulsa DistriOklahoma Natural Gas Company
Company 1993 to 1995 Vice President-Accounting of Oklahoma Natural Gas Company
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
17
<PAGE> 18
PART II.
ITEM 5. MARKET PRICE AND DIVIDENDS ON THE REGISTRANT'S
COMMON STOCK AND RELATED SHAREHOLDER MATTERS
(A) MARKET INFORMATION
The Company's common stock is listed on the New York Stock Exchange under the
trading symbol OKE. The corporate name ONEOK is used in newspaper stock
listings. The high and low market prices of the Company's common stock for each
fiscal quarter during the last two fiscal years were as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------- ---------------------------------------------
1998 High Low 1997 High Low
- ----------------------------------------------- ---------------------------------------------
<S> <C> <C> <S> <C> <C>
First Quarter $ 40 11/16 $ 31 3/16 First Quarter $ 28 5/8 $ 24 7/8
Second Quarter $ 40 11/16 $ 33 3/8 Second Quarter $ 30 7/8 $ 26
Third Quarter $ 44 1/4 $ 34 5/8 Third Quarter $ 31 1/8 $ 25 7/8
Fourth Quarter $ 40 15/16 $ 29 3/4 Fourth Quarter $ 35 5/16 $ 30
- ----------------------------------------------- ---------------------------------------------
</TABLE>
(B) HOLDERS
There were 11,768 holders of the Company's common stock at August 31, 1998.
(C) DIVIDENDS
Quarterly dividends declared on the Company's common stock during the last two
fiscal years were as follows:
<TABLE>
<CAPTION>
- ------------------------------------------
1998 1997
- ------------------------------------------
<S> <C> <C>
First Quarter $ 0.30 $ 0.30
Second Quarter $ 0.30 $ 0.30
Third Quarter $ 0.30 $ 0.30
Fourth Quarter $ 0.30 $ 0.30
- ------------------------------------------
Total $ 1.20 $ 1.20
==========================================
</TABLE>
Debt agreements pursuant to which the Company's outstanding long-term and
short-term debt has been issued limit dividends and other distributions on the
Company's common stock. Under the most restrictive of these provisions, $27.4
million of retained earnings is so restricted. On August 31, 1998, $243.1
million was available for dividends on the Company's common stock.
ITEM 6. SELECTED FINANCIAL DATA
Following are selected financial data for the Company for each of the last five
years. Dollar amounts are in millions of dollars, except per share amounts.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $1,835.4 $1,161.9 $1,224.3 $954.2 $784.1
Income before interest
and income taxes $203.5 $128.8 $121.0 $105.5 $92.0
Net income $101.8 $59.3 $52.8 $42.8 $36.2
Total assets $2,422.5 $1,237.4 $1,219.9 $1,181.2 $1,148.1
Long-term debt $329.3 $347.1 $351.9 $363.9 $376.9
Diluted earnings per common share $2.44 $2.13 $1.93 $1.58 $1.34
Dividends per common share $1.20 $1.20 $1.18 $1.12 $1.11
Percent of payout 49.2% 56.2% 61.1% 70.9% 82.8%
Common equity per share $19.01 $16.47 $15.21 $14.38 $13.88
Return on common equity 12.46% 12.75% 12.64% 10.90% 9.65%
Ratio of earning to fixed charges 5.50x 3.51x 3.28x 2.70x 2.52%
Ratio of earnings to combined fixed charges
and preferred stock dividend requirement 3.20x 3.48x 3.24x 2.67x 2.49x
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
18
<PAGE> 19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This Form 10-K (and certain other documents that are incorporated by reference
in this 10-K) contains statements concerning Company expectations or predictions
of the future that are "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995. These statements are intended
to be covered by the safe harbor provision of the Securities Act of 1933 and the
Securities Exchange Act of 1934. Forward-looking statements are based on
management's beliefs and assumptions based on information currently available.
It is important to note that actual results of Company earnings could differ
materially from those projected in such forward-looking statements. Factors that
may impact forward-looking statements include, but are not limited to, the
following: (I) the effects of weather and other natural phenomena; (ii)
increased competition from other energy suppliers as well as alternative forms
of energy; (iii) the capital intensive nature of the Company's business; (iv)
economic climate and growth in the geographic areas in which the Company does
business; (v) the uncertainty of gas and oil reserve estimates; (vi) the timing
and extent of changes in commodity prices for natural gas, electricity, and
crude oil; (vii) the nature and projected profitability of potential projects
and other investments available to the Company; (viii) conditions of capital
markets and equity markets; (ix) Year 2000 issues, and (x) the effects of
changes in governmental policies and regulatory actions, including income taxes,
environmental compliance and authorized rates. Accordingly, while the Company
believes these forward- looking statements to be reasonable, there can be no
assurance that they will approximate actual experience or that the expectations
derived from them will be realized. When used in Company documents, the words
"anticipate," "expect," "projection," "goal" or similar words are intended to
identify forward-looking statements. The Company does not have any intention or
obligation to update forward-looking statements after they distribute this 10-K
even if new information, future events or other circumstances have made them
incorrect or misleading.
OPERATING ENVIRONMENT AND OUTLOOK
Management believes that changes in the natural gas business are inevitable and
that such changes will significantly affect the manner in which natural gas and
related services are marketed. In response to this trend, commencing in 1994,
management conducted a strategic review of its business and of ongoing
developments in the natural gas distribution and energy related industry
regarding competition, regulation, and consolidation. Management concluded that
the domestic natural gas business was undergoing a process of deregulation which
would lead, over the next several years, to "unbundling" of services at the
residential level. Management further concluded that markets for electricity and
natural gas were converging and consolidating and that these trends and
competition for customers would alter the structure and business practices of
companies serving these markets in the future.
The Company continues to take steps to strengthen its competitive edge and
position it to be a leader in the industry. The most significant of these steps
was the strategic alliance with Western Resources, Inc. (Western) completed in
November of this fiscal year. The Company acquired the gas business of Western
and as a result became the eighth largest natural gas distributor in the country
serving approximately 1.4 million customers.
In order to better position the Company competitively, management determined
that it should seek both to expand its current operations and to become a
provider of energy services not limited to natural gas through acquisitions or
strategic alliances with companies that would enhance and expand its natural gas
distribution, marketing, production, and transportation business. In a step
toward this goal, ONEOK Power Marketing Company and has been authorized by the
Federal Energy Regulatory Commission (FERC) for the wholesale marketing of
electricity. Operations have not yet begun.
The Company continues to increase its investment in hydrocarbon reserves in its
service territory in order to add value to its existing production operations.
The Company focus remains on exploitation activities rather than exploratory
drilling.
The Company has strengthened its financial position and anticipates growth
through acquisition opportunities that will add value to all of the Company's
operations, divesting itself of properties that do not fit within the long term
goals of the Company, and maximizing the efficiency of its operations and
assets.
19
<PAGE> 20
OPERATING HIGHLIGHTS INCLUDE:
o REGULATED OPERATIONS - The natural gas operations acquired from Western
represent a strategic fit for the Company's regulated operations as
unbundling begins to unfold. Through the alliance, the Company obtained
both the local gas distribution business and MCMC, an intrastate gas
transportation company. MCMC is authorized to provide no-notice gas
transportation, wheeling, parking, balancing, and storage services to
third parties based on prevailing market prices.
Unbundling has the potential to enhance customer choices, provide
savings to consumers, increase throughput, and allow broader use of the
Company's assets. In January 1998, the OCC approved rule-making for the
restructuring of Oklahoma's natural gas utility industry. Under the
rules, the Company is required to unbundle its upstream activities.
During the third quarter, the Company filed an application in Oklahoma
in compliance with the OCC's new rules governing the restructuring. The
filing detailed how the Company plans to unbundle its upstream
activities, including gas transportation, storage, and supply, that are
required by the Company's distribution system and solicit competitive
bids for those services. The filing also requested permission to lower
the volume requirements for commercial and industrial customers who
wish to participate in the PCL program. On July 31, 1998 the OCC issued
an interim order on the Company's application that the Company believes
exceeds the Commission's jurisdiction and authority and contains
elements that are an "invasion of internal management discretion". The
Company has filed an appeal with the Oklahoma Supreme Court.
In Kansas, the Company has taken the first step toward unbundling its
services and providing customers choice by filing a proposed tariff
change reducing the minimum requirement for transportation service to
3,000 Mcf annually and to approve a revenue neutral residential basic
service charge and upstream capacity charges. If approved, this will
allow the KGS to expand transportation services to an additional 650
commercial and industrial customers and to restructure residential
customers bills to better reflect the difference between the basic
service charge for delivery and the cost of natural gas.
O NONREGULATED OPERATIONS - The Company continues to enhance the value of
it non-regulated operations through strategic acquisitions. Through the
Western alliance and other acquisitions, the Company has acquired
additional marketing, gathering, processing, and production businesses
which complement the activities of the existing operations.
The 1998 purchase by the Company of oil and gas reserves located in
Oklahoma and Kansas from OXY USA, Inc. added more than 400 wells to
total production property. Net production from these wells is
approximately 30 million cubic feet of gas per day and 400 barrels of
oil per day.
The acquisition of Washita Production Company, a Tulsa based
independent oil and gas producer, was closed in December 1997. The
transaction included 235 producing wells and significant behind pipe
and development drilling opportunities with proven reserves of
approximately 23 Bcfe.
The Company sold its interest in 12 non-operated gas processing plants
during fiscal 1998. The lack of ownership of the gathering systems
behind these plants was the primary motivation for the sale. The
Company no longer owns an interest in "fuel-and-shrink" plants, which
are subject to volatile swings in profitability.
The June 1998 acquisition of a 40 percent interest in K. Stewart
Petroleum Corp. increased the opportunities for the Company to expand
its oil and gas reserve base in the Anadarko Basin, one of North
America's most prolific gas fields.
The Company purchased an additional 55 percent interest in the Sycamore
Gas Gathering System on May 29, 1998. The purchase gives the Company a
97 percent interest in the system and control over the gathering and
processing company-owned production in that area.
20
<PAGE> 21
<TABLE>
<CAPTION>
CONSOLIDATED OPERATIONS
- -------------------------------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
FINANCIAL RESULTS
Operating revenues - regulated $971,905 $598,390 $538,169
Operating revenues - nonregulated 863,497 563,537 686,176
- -------------------------------------------------------------------------------
Total operating revenues 1,835,402 1,161,927 1,224,345
Operating costs 1,530,294 959,303 1,030,827
Depreciation, depletion and amortization 101,653 74,509 72,868
- -------------------------------------------------------------------------------
Income before income taxes and interest $203,455 $128,115 $120,650
===============================================================================
</TABLE>
RESULTS OF OPERATIONS - The Company's regulated and nonregulated operations
showed strong gains for the year as a result of the Company's acquisition
strategy and operating efficiencies achieved. Acquisition of the gas business
from Western added $45 million to income before interest and income taxes in the
regulated operations for the last three quarters of fiscal 1998 despite a warmer
than normal winter. For the year, income before interest and income taxes for
the regulated operations increased $49.6 million (49.7 percent) over 1997.
Decreases in operating expenses were due to operating efficiencies including
reductions in labor and associated welfare costs.
The increase in the income before interest and income taxes for the nonregulated
operation in fiscal 1998 was related to increased volumes for the marketing
operation including access to the retail market acquired as a result of the
Western transaction and the gain on the sale of certain gas processing plants.
The performance of the nonregulated operations played a major role in the
increase in income before taxes in 1997. The strong performance reflects the
effect of additional gas reserves acquired, operational changes and
efficiencies, general market conditions and an aggressive marketing campaign by
the Company's gas marketing operation.
RISK MANAGEMENT - To minimize the risk from market fluctuations in the price of
natural gas and oil, the Company's nonregulated operations use commodity
derivative instruments such as future contracts, swaps, and options
(collectively, derivatives) to hedge existing physical gas inventory, and
purchase or sale commitments. None of these derivatives are held for speculative
purposes and, in general, the Company's risk management policy requires that
positions taken with derivatives be offset by positions in physical transactions
or other derivatives. For each year in the three year period ended August 31,
1998, derivatives were primarily used by ONEOK Gas Marketing as a method of
eliminating unacceptable risks with respect to changes in the price of gas or
the cost of the intervening transportation associated with certain contracts.
Kansas Gas Service Company began using derivative instruments to hedge the cost
of anticipated gas purchases during the winter heating months to protect its
customers from upward volatility in the market price of natural gas. The gain or
loss resulting from such derivatives will be combined with the physical cost of
gas and recovered from the customer through the gas purchase clause in rates.
The Company's production segment utilizes derivatives in order to hedge
anticipated sales of oil and natural gas production. These anticipated
transactions have been hedged with commodity swaps agreements whereby the
Company is able to set the price to be received for the future production thus
eliminating the risk of declining market prices between the origination date of
the swap and the month of production. The Company's strategy in hedging
anticipated transactions is to eliminate the variability in earnings of its
production segment as a result of market fluctuations. To the extent that
management does not terminate a hedge or enter into an opposing derivative, the
current strategy will limit the potential gains which could result from
increases in market prices above the level set by the hedge.
The Company adheres to policies and procedures which limit its exposure to
market risks from open positions and monitors daily its exposure to market risk.
The results of the Company's derivative trading activities continue to meet its
stated objectives. For further discussion, see Item 7A - Quantitative and
Qualitative Disclosures About Market Risk at page 31 and Note C of "Notes to
Consolidated Financial Statements."
21
<PAGE> 22
YEAR 2000. We are currently addressing the effect of Year 2000 (Y2K) issue on
our reporting systems and operations. TheY2K issue arose because many computer
systems and application software (IT applications), and plant and equipment
(Embedded Technology) were constructed using an abbreviated date field which
eliminates the first two digits of the year, assuming that these two digits
would always be "19". On January 1, 2000 these systems may incorrectly recognize
the date as January 1, 1900. Some IT applications and Embedded Technology may
incorrectly process critical financial and operating information or stop
processing altogether.
The Company recognized this potential problem and began rewriting and
remediating its existing IT applications and Embedded Technology. The Company's
mainframe software is approximately 60 percent compliant with all other systems
being 80 percent compliant. The Company estimates that approximately 75 percent
of Embedded Technology, which the Company deems significant to their operations,
is year 2000 compliant. Remediated programs are being tested prior to being
declared compliant. The estimated completion date of this program is April,
1999, provided that the Company is able to retain, or replace if required, such
key personnel as necessary for the conversion of its remaining programs and
applications.
The primary business risk associated with Y2K is the Company's ability to
continue to transport and distribute gas to its customers without interruption.
In the event the Company and/or its suppliers and vendors are unable to
remediate the Y2K problem prior to January 1, 2000, operations of the Company
could be significantly impacted. In order to mitigate this risk, the Company is
developing a contingency plan to continue operations through manual intervention
and other procedures should it become necessary to do so. Such procedures are
expected to include back-up power supply for its critical pipeline and storage
operations and, if necessary, curtailment of supply. The Company's significant
storage capacity could be used to supplement system supply in the event its
suppliers can not make deliveries. The Company expects to complete its
operational contingency plan by the end of fiscal 1999.
The Company is assessing operational risks related to suppliers and vendors with
whom they conduct business. Based on this assessment, the Company is in the
process of contacting their suppliers and vendors, deemed to be strategic to its
operations, concerning Y2K compliance. The Company plans to test such third
party compliance to the extent deemed reasonable and necessary to determine
compliance.
There can be no assurance that the Company's systems or the systems of other
companies on which the Company relies, will be converted in a timely manner or
that any such failure to convert would not have a material adverse effect on the
Company.
The Company has spent approximately $1 million to prepare their systems for Y2K
compliance and expects remaining costs to be comparable.
ACCOUNTING POLICIES - The regulated operations of the Company are primarily
subject to accounting requirements of the OCC, KCC, and the provisions of
Statement of Financial Accounting Standards No. 71 "Accounting for the Effects
of Certain Types of Regulation." Accordingly, the allocation of costs and
revenues to accounting periods for ratemaking and regulatory purposes may differ
from bases generally applied by nonregulated companies. Such allocations to meet
regulatory accounting requirements are considered to be generally accepted
accounting principles for regulated utilities provided that there is a
demonstrable ability to recover any deferred costs in future rates. Pursuant to
the provisions of SFAS No. 71, the regulated business has recognized regulatory
assets of $229.5 million of which $58.6 million has been established for amounts
not currently being recovered in rates pending Company filings. However, in the
event regulated operations no longer meet the criteria for following SFAS No. 71
due to unbundling or other actions, a write-off of regulatory assets and
stranded costs may be required.
SEGMENT OPERATIONS - The Company views its segments as operating within either a
rate regulated (regulated operations) or a nonregulated environment
(nonregulated operations). The nonregulated environment is further viewed as
having three primary, vertically integrated segments: marketing, gathering and
processing, and production.
22
<PAGE> 23
REGULATED OPERATIONS
The regulated business unit provides natural gas distribution, transportation,
gas supply, and storage services in Oklahoma and Kansas. The Company's
operations in Oklahoma are conducted through Oklahoma Natural Gas Company
Division, ONEOK Gas Transportation Company Division and three wholly-owned
subsidiaries, ONEOK Gas Transportation, L.L.C., ONG Transmission Company, and
ONG Sayre Storage Company, which together form an integrated intrastate natural
gas distribution and transmission business which serves residential, commercial,
and industrial customers in about 75 percent of the state of Oklahoma. These
companies will be collectively referred to herein as Oklahoma Natural Gas (ONG).
The Company's operations in Kansas are conducted through Kansas Gas Service
Company Division (Kansas Gas Service) and Mid Continent Market Center (MCMC), a
wholly owned transportation company. These companies will be collectively
referred to herein as KGS. KGS's regulated gas operations are primarily engaged
in distribution and intrastate gas transportation, as well as gas wheeling,
parking, balancing and storage services. Kansas Gas Service serves residential,
commercial, and industrial customers in about 67 percent of Kansas. Kansas Gas
Service also conducts regulated gas distribution operations in northeastern
Oklahoma. ONG is subject to regulatory oversight by the OCC. KGS and MCMC are
subject to regulatory oversight by the KCC and/or the OCC.
Identifiable assets at August 31, 1998, included $972.6 million acquired through
the alliance with Western.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
FINANCIAL RESULTS
Gas Sales $883,089 $543,662 $487,294
Cost of Gas 527,738 308,057 247,299
- -----------------------------------------------------------------------------
Gross margins on gas sales 355,351 235,605 239,995
PCL, ECT and transportation margins 81,763 41,974 41,684
Other revenues 29,897 13,890 11,394
- -----------------------------------------------------------------------------
Net revenues 467,011 291,469 293,073
Operating expenses 238,607 140,328 145,299
Depreciation, depletion and amortization 79,032 51,375 50,805
- -----------------------------------------------------------------------------
Income before income taxes and interest $149,372 $99,766 $96,969
=============================================================================
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------
<S> <C> <C> <C>
Gross Margin per Mcf
OKLAHOMA
Residential $2.99 $2.94 $3.09
Commercial $2.40 $2.19 $2.28
Industrial $1.13 $0.95 $0.85
Pipeline capacity leases $0.24 $0.19 $0.20
KANSAS
Residential $2.24 - -
Commercial $1.75 - -
Industrial $1.92 - -
End-use customer - -
transportation $0.56
===========================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------
1998 1997 1996
- ----------------------------------------------------------------
<S> <C> <C> <C>
Number of customers
Oklahoma 739,684 733,621 729,467
Kansas 652,330 - -
- ----------------------------------------------------------------
Total 1,392,014 733,621 729,467
================================================================
Capital expenditures (thousands)
Oklahoma $67,792 $67,747 $42,900
Kansas 46,032 - -
- ----------------------------------------------------------------
Total $113,824 $67,747 $42,900
================================================================
Identifiable assets (millions) $1,932 $1,026 $1,019
================================================================
Customers per employee
Oklahoma 475 477 403
Kansas 489 - -
- ----------------------------------------------------------------
</TABLE>
Operational Highlights - The Company dominates the core energy service markets
with over a 90 percent market share for water heating, cooking, and home
heating. Annual cost comparisons with electricity for these same services in
Oklahoma and Kansas indicate that gas costs were at least 50 percent less, the
largest difference being in home heating at 70 percent less. On a gas to gas
comparison, the Company's rates in Oklahoma and Kansas were lower than the
regional and national averages for residential, firm industrial, and
interruptible service.
Highlights of significant operating changes over the past three years include:
o Addition of approximately 660,000 new distribution customers and 1,400
employees in KGS acquisition.
23
<PAGE> 24
o Signed contract and began transporting gas to four natural gas-fired
electric generating plants owned by Public Service Company of Oklahoma
under PCL agreements. Construction on facilities to serve the plants
was completed early in fiscal 1998.
o Strengthened cost controls throughout the organization. Total employees
in Oklahoma dropped by approximately 9.63 percent during the 1998
fiscal year. This was accomplished through attrition and without
compromising customer safety or service. Operating expense per customer
decreased 4.5 percent.
o Injection capabilities were increased by 70 percent in one Oklahoma
storage field while withdrawal capabilities were increased by over 80
percent. In another Oklahoma storage field, work will be completed by
December, 1998 which will increase the injection capabilities by 50
percent and double the withdrawal capabilities.
o A $10 million project to increase the capacity of a storage field in
Kansas is scheduled for completion in 2000. Total storage capacity in
Kansas will increase by almost 40 percent.
REGULATORY INITIATIVES - The KCC has approved a pilot program designed to
moderate the cost its customers pay for natural gas in cold weather months.
Under the program, Kansas Gas Service will use hedges to cap the price of its
anticipated winter heating season gas purchases in order to protect customers
from the upward volatility during the winter heating months.
The KCC has approved a pilot program in Kansas that would offer residential
customers the option of paying a fixed monthly bill. The program will allow a
qualified residential customer the option of paying an amount based on the
projected average annual usage rather than actual usage. The program will
initially be offered to 100,000 customers.
A similar program is already in effect for customers in Oklahoma.
In a first step toward unbundling in Kansas, a proposed tariff change was filed
which would reduce the minimum requirement for transportation service to 3,000
Mcf annually and approve a revenue neutral residential basic service charge and
upstream capacity charges. If approved, this will allow KGS to extend
transportation services to an additional 650 commercial and industrial customers
and restructure residential customer bills to better reflect the differences
between the basic service charge for delivery and the cost of natural gas.
During fiscal 1998, ONG filed an application in Oklahoma in compliance with the
Oklahoma Corporation Commission's (OCC) new rules governing the restructuring of
the state's natural gas industry. Since then, the Company and the OCC have
reached an impasse. The ultimate outcome of these proceedings and their impact,
if any, on future earnings and cash flow can not be predicted at this time.
CAPITAL EXPENDITURES - The Company's capital expenditure program includes
expenditures for extending service to new areas, increasing system capabilities,
and general replacements and betterments. It is the Company's practice to
maintain and periodically upgrade facilities to assure safe, reliable, and
efficient operations. The 1998 capital expenditure program included $19 million
for new business development including $5.3 to provide service to Public Service
Company of Oklahoma's (PSO) gas-fired electric generation plants and $12 million
to improve injection capabilities and peak storage deliverability. The 1997
capital expenditure program included $49 million for new business development
including $13.4 to provide service to PSO's four power plants and $7 million to
improve compression and peak storage deliverability. The 1996 capital
expenditure program included $10 million for new business development and $2
million to improve peak storage deliverability.
OPERATING RESULTS - Net revenues and operating expenses increased over the same
period one year ago, primarily due to inclusion of KGS's operations since
December 1, 1997. On a pro forma basis, assuming the Western acquisition had
occurred at the beginning of fiscal 1997, net revenues and operating expenses
would have been $514.3 million and $279.7 million, respectively, for fiscal 1998
as compared to $644.7 million and $297.3 million respectively, for fiscal 1997.
The decrease in pro forma net revenues in the current year reflects the fact
that KGS's rates are not weather normalized as are ONG's and, accordingly, were
negatively impacted by warmer than normal weather. Pro forma operating expenses
have declined in the current year reflecting ongoing efforts to improve
operating efficiencies while increasing total customers served. Personnel costs,
including pensions and postretirement costs, on a pro forma basis, decreased
from
24
<PAGE> 25
the prior year partially due to a reduced personnel complement achieved solely
through attrition. Other cost reductions related to occupancy costs and reduced
levels of contract labor.
In 1997 lower gross margins on gas sales result primarily from lower usage by
customers whose gas sales and degree days are not normalized, increased cost of
gas used in operations, and unrecovered gas costs. Actual degree days in 1997
were 3,566 as compared to 3,617 in 1996. Degree days is an industry measure of
temperature variations from an established normal temperature of 65 degrees; a
higher number of degree days reflects colder weather on the average. Operating
expenses decreased in 1997 as compared to 1996 primarily due to reductions in
labor and associated employee welfare costs.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------
<S> <C> <C> <C>
Volumes (MMcf)
Gas sales
Residential 103,700 58,241 55,801
Commercial 42,452 29,408 28,548
Industrial 7,262 11,384 15,145
PCL and ECT 226,058 173,134 158,527
- -------------------------------------------------------------------
Total gas sales, PCL and ECT 379,472 272,167 258,021
===================================================================
</TABLE>
The statistics presented for the 1998 fiscal year include volumes attributable
to Kansas Gas Service since December 1, 1997.
NONREGULATED OPERATIONS
The Company's nonregulated operations are involved in the marketing, gathering
and processing, and production of natural gas and natural gas liquids. The gas
marketing subsidiary has directed its activities toward wholesale and retail
sales in the mid-continent region of the United States. The Company's interests
in gas liquids extraction plants and producing properties are concentrated
principally in Oklahoma, Kansas, and New Mexico. The production subsidiary has
concentrated on production in existing fields. The Company also operates its
headquarters office building and a parking garage.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
FINANCIAL RESULTS
COMBINED NONREGULATED OPERATIONS
Gas Sales $774,455 $484,674 $612,595
Cost of Gas 758,688 470,878 596,491
- -----------------------------------------------------------------------------------
Gross margins on gas sales 15,767 13,796 16,104
Gas and oil production 42,315 38,159 25,181
Gas processing (net) 22,846 25,326 20,902
Other 49,090 9,534 16,560
- -----------------------------------------------------------------------------------
Net revenues 130,018 86,815 78,747
Operating expenses 53,314 35,332 33,002
Depreciation, depletion and amortization 22,621 23,134 22,064
- -----------------------------------------------------------------------------------
Income before income taxes and interest $54,083 $28,349 $23,681
===================================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas volumes (MMcf)
Marketing 334,364 205,204 309,965
Natural gas production 16,818 14,565 9,406
Residue gas 5,771 6,109 6,883
- -------------------------------------------------------------------
Total natural gas volumes 356,953 225,878 326,254
- -------------------------------------------------------------------
Less intersegment sales
Marketing 13,392 9,384 7,822
Natural gas production 5,306 6,652 3,978
Residue gas 5,771 6,109 6,880
- -------------------------------------------------------------------
Total intersegment sales 24,469 22,145 18,680
- -------------------------------------------------------------------
Net natural gas volumes 332,484 203,733 307,574
===================================================================
</TABLE>
MARKETING
OPERATIONAL HIGHLIGHTS - The Company's marketing operation purchases and markets
natural gas, primarily in the mid-continent area of the United States. The
Company continues to focus on daily trading rather than on low margin baseload
trading. The alliance with Western has significantly increased gas sales volumes
by adding a retail customer base. In 1997, the Company was the successful bidder
to serve four gas-fired electric generating plants owned by Public Service
Company of Oklahoma.
25
<PAGE> 26
<TABLE>
<CAPTION>
- --------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- --------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $774,455 $484,674 $612,595
Cost of Gas 758,688 470,878 596,491
- --------------------------------------------------------
Gross margins on gas sales 15,767 13,796 16,104
Other 4,159 (1,475) 1,221
- --------------------------------------------------------
Operating revenues 19,926 12,321 17,325
Operating costs, net 7,024 3,991 3,931
Depreciation, depletion
and amortization 561 482 484
- --------------------------------------------------------
Income before income taxes and
interest $12,341 $7,848 $12,910
========================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
1998 1997 1996
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING INFORMATION
Natural gas volumes (MMcf) 334,364 205,204 309,965
Capital expenditures (thousands) $0 $373 $370
Identifiable assets (thousands) $123,936 $63,828 $71,186
============================================================================
</TABLE>
Price Risk Management - In order to mitigate the financial risks arising from
fluctuations in both the market price and transportation costs of natural gas,
the Company routinely enters into natural gas futures contracts, swaps, and
options as a method of protecting its margins on the underlying physical
transactions. However, net open positions in terms of price, volume, and
specified delivery point do occur. For further discussion, see Item 7A -
Quantitative and Qualitative Disclosures About Market Risk.
OPERATING RESULTS - The increase in gross margins is primarily attributable to
increased throughput; however, this was offset by lower gross margins per Mcf.
Lack of extreme weather changes across the country during this year's winter
resulted in less volatility in prices and less opportunity to take advantage of
the volatility. Increased sales volumes are due to additional customers acquired
in the alliance with Western and the addition of service to the four gas-fired
electric generating plants owned by Public Service Company of Oklahoma. The
increase in operating costs is due to the additional expenses related to retail
marketing.
The Company's focus on daily trading and away from baseload trading had a
significant impact on the operating results of the marketing segment in 1997.
Overall gross margins per Mcf increased in 1997 over the prior year despite a
decrease in both volumes sold and total gross margins. The decrease in volumes
is indicative of management's decision to forgo baseload business in order to
further develop its daily trading practice. Margins in the daily trading were
favorably affected by weather related demand. The decrease in other operating
revenue in 1997 over 1996 is the result of a non-recurring charge.
GATHERING AND PROCESSING
OPERATIONAL HIGHLIGHTS - The Company's processing operation owns and operates
two gas processing plants and related gathering systems and has nonoperating
interests in two gas processing plants. The gas processing operations include
the extraction of natural gas liquids (NGL's) and the separation
("fractionation") of mixed NGLs into component products (e.g., ethane/propane
mix, propane, iso and normal butane, and natural gasoline). The component
products are used for petrochemical feedstock, residential heating and cooking
in rural areas, and blending into motor fuels. The industry as a whole operates
substantial numbers of such plants, many owned by large integrated oil and gas
companies and independents.
The Company's gathering operation supplies gas gathering and compression
services to producers. The purchase of an additional 55 percent interest in the
Sycamore Gas Gathering System effective June 1, 1998, gives the Company control
over the company-owned production in that area. The Company's sale of its
interest in eleven gas processing plants in the second quarter and one gas
processing plant in the third quarter of 1998 eliminated the Company's interest
in "fuel-and-shrink" plants, which are subject to volatile swings in
profitability. Through the Western alliance in fiscal 1998, the Company
acquired the Minneola Gas Processing Plant located in Kansas and an additional
34 percent interest in the Indian Basin Plant. An eight percent interest in the
Indian Basin had been acquired in fiscal 1997.
26
<PAGE> 27
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Gas processing (net) $21,646 $23,107 $18,423
Gathering 363 - -
Other 19,187 (65) 261
- --------------------------------------------------------------------------
Operating revenues 41,196 23,042 18,684
Operating costs, net 7,988 7,770 7,641
Depreciation, depletion
and amortization 2,249 2,393 2,063
- --------------------------------------------------------------------------
Income before income taxes and
interest $30,959 $12,879 $8,980
==========================================================================
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING INFORMATION
Residue gas (MMcf) 5,771 6,109 6,883
Natural gas liquids (MGal) 197,342 200,143 195,979
Average NGL's price (MGal) $0.302 $0.365 $0.297
Fuel & Shrink price (MMbtu) $2.56 $2.07 $1.82
Capital expenditures (thousan $18,379 $10,563 $5,183
Identifiable assets (thousand) $63,214 $36,049 $26,870
==========================================================================
</TABLE>
Capital Expenditures - The Company purchased an additional 55 percent interest
in the Sycamore Gas Gathering System in 1998 giving the Company a 97 percent
interest in the system and control over the company-owned production in that
area. The remaining $10.3 million in capital expenditures relates to the
purchase of additional gas plant interests and $3.8 million in capital required
to sustain operations. Fiscal 1997 expenditures included $9 million incurred to
purchase an interest in the Indian Basin Plant as well as sustain and improve
operations. The remaining expenditures and those in 1996 generally relate to
sustaining capital improvements.
OPERATING RESULTS - The Company's sale of its interest in 12 gas processing
plants in 1998 resulted in a decrease in volumes over the same period one year
ago. This was partially offset as a result of the additional interest in the
Indian Basin Plant and the addition of the Minneola Plant. Average NGL price per
gallon decreased for the year over one year ago as prices continue to experience
a downward correction from the abnormally high prices prevalent throughout much
of fiscal 1997 and coincide with a decline in crude oil prices. Other revenue
includes the gain on the sale of the "fuel and shrink" plants.
Volumes of natural gas liquids sold increased and higher product prices resulted
in an increase in natural gas liquids revenues for 1997. Volumes declined in
1996 due to some periods of ethane rejection but natural gas liquids were
strengthened by increased prices.
PRODUCTION
OPERATIONAL HIGHLIGHTS - The Company's strategy is to concentrate ownership of
hydrocarbon reserves in its service territory in order to add value not only to
its existing production operations but also to the related gathering and
processing, marketing, transportation, and storage businesses. Accordingly, the
Company focuses on exploitation activities rather than exploratory drilling. As
a result of recent acquisitions, the number of wells the Company operates has
increased. In its role as operator, the Company controls operating decisions
which impact production volumes and lifting costs.
<TABLE>
<CAPTION>
- -----------------------------------------------------------
(Thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $37,123 $31,496 $17,465
Oil sales 5,192 6,663 7,716
Liquids and residue 1,200 2,219 2,478
Other 940 699 5,675
- -----------------------------------------------------------
Operating revenues 44,455 41,077 33,334
Operating costs, net 14,671 12,468 11,341
Depreciation, depletion
and amortization 18,872 19,899 19,161
- -----------------------------------------------------------
Income before income taxes and
interest $10,912 $ 8,710 $ 2,832
===========================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
1998 1997 1996
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves
Gas (MMcf) 178,047 83,293 74,068
Oil (MBbls) 3,272 2,014 2,010
- ----------------------------------------------------------------------------------
Production
Gas (MMcf) 16,818 14,565 9,406
Oil (MBbls) 330 336 435
- ----------------------------------------------------------------------------------
Average price
Gas (Mcf) $2.21 $2.16 $1.86
Oil (Bbls) $15.70 $19.84 $17.73
- ----------------------------------------------------------------------------------
Capital expenditures (thousands) $167,669 $32,911 $46,733
Identifiable assets (thousands) $246,102 $100,062 $73,648
==================================================================================
</TABLE>
RISK MANAGEMENT - Since the volatility of energy prices has a significant impact
on the profitability of this segment, the Company utilizes commodity derivative
instruments in order to offset this risk. As of August 31, 1998, approximately
50 percent of anticipated production in 1999 has been hedged primarily with swap
agreements. This
27
<PAGE> 28
compares to 25 percent of 1998 production hedged at August 31, 1997. See Item 7A
- - Quantitative and Qualitative Disclosure about Market Risk.
CAPITAL EXPENDITURES - The Company purchased natural gas and oil reserves from
OXY USA, Inc. in fiscal 1998. The reserves are located in Oklahoma and Kansas
and include more than 400 wells. Net production is approximately 30 million
cubic feet of gas per day and 400 barrels of oil per day and includes a gas
sweetening plant. The purchase price was approximately $128 million before
adjustments. Based on estimated reserves, this transaction will almost double
the Company's oil and gas reserves.
A 40 percent equity interest in the K. Stewart Petroleum Corp., was acquired on
June 2, 1998. The acquisition creates opportunities to expand ownership of oil
and gas reserves in the Anadarko Basin and for the Company to achieve its
strategic objective of growing its reserves base in areas where it has other
energy-related operations.
The acquisition of Washita Production Company was closed in December, 1997. The
acquisition of Washita, valued at approximately $20 million, was made with a
combination of cash and ONEOK, Inc. common stock. The transaction includes 235
producing wells and significant behind pipe and development drilling
opportunities with proven reserves of approximately 23 billion cubic feet
equivalent. The wells are primarily located in the Anadarko and Arkoma Basin of
Oklahoma and include some properties in the Hugoton Basin of Kansas.
During 1997, the Company purchased PSEC, Inc., an independent oil and gas
company in Oklahoma. The transaction included 180 wells with proven reserves of
20 Bcf of natural gas and 167,000 barrels of oil. Included in the transaction
was PSPC, Ltd., which operates and holds a 42 percent interest in the Sycamore
Gas Gathering System. The purchase was financed with $9.3 million in long-term
debt and 334,252 shares of ONEOK Inc. common stock.
Capital expenditures primarily related to a limited developmental drilling
program were approximately $16.5 million, $6.7 million, and $3.4 million in
1998, 1997, and 1996, respectively.
OPERATING RESULTS - The increased gas production is primarily related to the
additional proved reserves acquired as a result of the OXY, PSEC and Washita
Production Company property acquisitions. Production from these properties more
than offset the natural decline in production from other fields. The increase in
operating costs in 1998 as compared to one year ago is indicative of the
increase in the total number of fields owned by the Company.
The increase in gas production volumes in 1997 over 1996 was attributable to the
effects of gas reserves acquired in the latter part of fiscal 1996 and
operational changes and efficiencies. The increase in the average price of gas
and oil in 1997 was attributable to general market conditions. The Company
recognized an $8.6 million impairment loss in fiscal 1996 upon the adoption of
Statement of Financial Accounting Standard No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.
LIQUIDITY AND CAPITAL RESOURCES
In August 1998, the Company registered a shelf filing for $400 million in debt
securities. The filing allows the Company to sell the debt securities over a two
year period as needed. These funds will be used in the future to retire
short-term debt and for other general corporate purposes.
CASH FLOW ANALYSIS
Cash provided by operating activities remains strong and continues as the
primary source for meeting cash requirements. However, due to seasonal
fluctuations and additional capital requirements, the Company periodically
accesses funds through short-term credit agreements and, if necessary, through
long-term borrowing. The Company believes that internally generated funds and
existing credit agreements will be sufficient to meet its debt service, dividend
payment, and capital expenditure requirements, excluding significant capital
acquisitions. The following discussion of cash flows should be read in
conjunction with the Company's "Consolidated Statement of Cash Flows" and the
supplemental cash flow information included in Note M of "Notes to Consolidated
Financial Statements."
28
<PAGE> 29
OPERATING CASH FLOWS
Operating cash flows for the year ended August 31, 1998, increased substantially
as compared to the same period in 1997. This increase is due to the liquidation
of the abnormally high net working capital acquired in the Western acquisition,
increased operating income and favorable changes in assets and liabilities,
including recovery of purchased gas costs.
Operating cash flows for 1997 as compared to 1996 are higher as a result of
higher earnings and lower net invested working capital. The lower net invested
working capital is primarily due to lower levels of gas in storage and recovery
of purchased gas costs.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
FOR THE YEARS ENDED AUGUST 31, 1998 1997 1996
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Cash provided by operating activitis $346,526 $152,051 $105,050
- --------------------------------------------------------------------------
</TABLE>
INVESTING CASH FLOWS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
FOR THE YEARS ENDED AUGUST 31, 1998 1997 1996
(THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Cash used in investing activities $299,714 $88,832 $71,985
- -------------------------------------------------------------------------
</TABLE>
[CHART]
Capital Expenditures - Capital expenditures totaled $306 million in 1998.
Acquisition of production and processing assets totaled approximately $164
million, $34 million, and $43 million for 1998, 1997, and 1996, respectively.
Capital expenditures for 1999 are estimated to be $268 million.
ASSET SALES - Approximately $30 million of proceeds was received in fiscal 1998
from the sale of gas processing assets. Approximately $18 million of proceeds
was received in 1996 resulting from the sale of production assets.
FINANCING CASH FLOW
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------
FOR THE YEARS ENDED AUGUST 31, 1998 1997 1996
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------
<S> <C> <C> <C>
Cash used in financing activities $61,103 $49,440 $44,966
- ------------------------------------------------------------------------
</TABLE>
SHORT-TERM DEBT - At August 31, 1998, $212 million of short-term debt was
outstanding. A short-term unsecured credit agreement with several banks provides
aggregate borrowing of up to $200 million for general corporate purposes. The
Company also has additional credit facilities available through a master note
with Bank of America. The maximum amount of short-term debt authorized by the
Board of Directors is $225 million. Fluctuation in the amount of cash used in
financing activities in each of the years presented is primarily a factor for
short-term borrowing and the significant increase in preferred stock dividend
requirements..
LONG-TERM DEBT - As of August 31, 1998, the Company could have issued $874
million of additional long-term debt under the most restrictive provisions
contained in its various borrowing agreements. At August 31, 1998, the equity
component was 68 percent as compared to 54 percent a year ago. On December 1,
1997, Moody's Investors Service announced that it had upgraded the Company's
debt rating from A3 to A2 due to the benefits expected from the
29
<PAGE> 30
acquisition of the gas business, including strengthened market and financial
positions. The debt rating by Standard and Poor's Corporation was upgraded from
A- to A. Long-term debt in the amount of $9.3 million was issued in 1997 as
partial payment for PSEC, Inc. and affiliates.
STOCK AND DIVIDENDS - The Company had approximately 32 million shares of common
stock outstanding at August 31, 1998. The Common stock dividends were $1.20,
$1.20, and $1.18 per share in 1998, 1997, and 1996, respectively. Convertible
preferred stock dividends were $1.80 and $1.50 per share in 1998 for Series A
and Series B, respectively. Preferred stock dividends were, $1.78, and $2.38 per
share in 1997 and 1996, respectively. Through the Company's Stock Purchase and
Dividend Reinvestment Program $4.1 million and $5.5 million of dividends were
reinvested into common stock in 1998 and 1997, respectively.
LIQUIDITY
The regulated segment continues to face competitive pressure to serve the
substantial market represented by its large volume customers. The loss of a
substantial portion of that load, without recoupment of the revenues from that
loss, could have a materially adverse effect on the Company's financial
condition. However, since 1995, rates have been structured to reduce the
Company's risk in serving its large volume customers.
OTHER
ENVIRONMENTAL - In connection with the Western transaction, the Company acquired
12 manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials that are classified as hazardous material.
Hazardous materials are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the Kansas
Department of Health and Environment (KDHE) presently governs all future work at
these sites. The terms of the consent agreement allow the company to investigate
these sites and set remediation priorities based upon the results of the
investigations and risk analysis. The prioritized sites will be investigated
over a ten year period. At August 31, 1998, the costs of the investigations and
risk analysis have been minimal. Limited information is available about the
sites and no testing has been preformed. Management's best estimate of the cost
of remediation ranges from $100 thousand to $10 million per site based on a
limited comparison of costs incurred to remediate comparable sites. These
estimates do not give effect to potential insurance recoveries, recoveries
through rates or from third parties. The KCC has permitted others to recover
their remediation costs through rates. It should be noted that additional
information and testing could result in costs significantly below or in excess
of the amounts estimated above. To the extent that such remediation costs are
not recovered, the costs could be material to the Company's results of
operations and cash flows depending on the degree of remediation required and
number of years over which the remediation must be completed.
NEW ACCOUNTING PRONOUNCEMENTS - In June 1997, the Financial Accounting Standards
Board (FASB) issued Statement of Financial Accounting Standards No. 130,
Reporting Comprehensive Income (SFAS 130). SFAS 130 establishes standards for
reporting and display of comprehensive income and its components in a full set
of general purpose financial statements. It does not, however, specify when to
recognize or how to measure items that make up comprehensive income. SFAS 130
was issued to address the concerns over the practice of reporting elements of
comprehensive income directly in equity. SFAS 130 is effective for annual
periods beginning after December 15, 1997.
In June 1997, the FASB issued Statement of Financial Accounting Standards No.
131, Disclosures about Segments of an Enterprise and Related Information (SFAS
131). SFAS 131 supersedes SFAS No. 14, Financial Reporting for Segments of a
Business Enterprise but retains the requirement to report information about
major customers. SFAS 131 replaces the "industry segment" concept of Statement
14 with a "management approach" concept as the basis for identifying reportable
segments. The management approach is based on the way that management organizes
the segments within the enterprise for making operating decisions and assessing
performance. Consequently, the segments are evident from the structure of the
enterprise's internal organization. It focuses on financial information that an
enterprise's decision makers use to make decisions about the enterprise's
operating matters. SFAS 131 is effective for financial statements for periods
beginning after December 15, 1997, and is not anticipated to have a significant
impact on the Company's segment reporting.
30
<PAGE> 31
In February 1998, the FASB issued Statement of Financial Accounting Standards
No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits
(SFAS 132), which is required to be implemented for fiscal years beginning after
December 15, 1997. SFAS 132 revises employers' disclosures about pension and
other postretirement benefit plans. It does not change the measurement or
recognition of those plans.
Statement of Financial Accounting Standards No. 133, Accounting for Derivatives
Instruments and Hedging Activities (SFAS 133), was issued by the FASB in June
1998. Statement 133 standardizes the accounting for derivatives instruments,
including certain derivative instruments embedded in other contracts. Under the
standard, entities are required to carry all derivative instruments in the
balance sheet at fair value. The accounting for changes in the fair value of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, on the reason for holding it. If
certain conditions are met, entities may elect to designate a derivative
instrument as a hedge of exposures to changes in fair values, cash flows, or
foreign currencies. If the hedge exposure is a fair value exposure, the gain or
loss on the derivative instrument is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item attributable
to the risk being hedged. If the hedged exposure is a cash flow exposure, the
effective portion of the gain or loss on the derivative instrument is reported
initially as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. Any amounts excluded from the assessment of hedge effectiveness as
well as the ineffective portion of the gain or loss is reported in earnings
immediately. The Company must adopt Statement 133 by September 1, 1999; however,
early adoption is permitted.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
RISK MANAGEMENT - The Company, substantially through its nonregulated segments,
is exposed to market risk in the normal course of its business operations to the
impact of market fluctuations in the price of natural gas and oil. Market risk
refers to the risk of loss in cash flows and future earnings arising from
adverse changes in commodity energy prices. The Company's primary exposure
arises from fixed price purchase or sale agreements which extend for periods of
up to 48 months, gas in storage inventories utilized by the gas marketing
operation, and anticipated sales of oil and gas production. To a lessor extent,
the Company is exposed to risk of changing prices or the cost of intervening
transportation resulting from purchasing gas at one location and selling it at
another (hereinafter referred to as basis risk). To minimize the risk from
market fluctuations in the price of natural gas and oil, the Company uses
commodity derivative instruments such as future contracts, swaps and options to
hedge existing or anticipated purchase and sale agreements, existing physical
gas in storage, and basis risk (See Note G to the Consolidated Financial
Statements.). None of these derivatives are held for speculative purposes. The
Company adheres to policies and procedures which limit its exposure to market
risk from open positions and monitors its exposure to market risk. The results
of the Company's derivative hedging activities continue to meet its stated
objective.
All of the Company's long-term debt is fixed-rate and, therefore, does not
expose the Company to the risk of earnings or cash flow loss due to changes in
market interest rates. Such debt is not traded in the open market and,
accordingly, changes in its fair value due to changes in interest rates will
have no impact on future earnings or cash flows.
Kansas Gas Service began using derivative instruments to hedge the cost of
anticipated gas purchases during the winter heating months to protect its
customers from upward volatility in the market price of natural gas. The gain or
loss resulting from such derivatives will be combined with the physical cost of
gas and recovered from the customer through the gas purchase clause in rates.
The Company has no market risk associated with such activities and, accordingly,
these derivatives have been omitted from the value-at-risk disclosures below.
VALUE-AT-RISK DISCLOSURE OF MARKET RISK- The estimation of potential losses that
could arise from changes in market conditions is typically accomplished through
the use of statistical models that seek to predict risk of loss based on
historical price and volatility patterns. The value-at-risk (VAR) measurement
used by the Company is based on J.P. Morgan's RiskMetricsTM model, which
measures recent volatility and correlation in the price of natural gas and oil,
pulls through current price levels and net deltas, and applies estimates made by
management regarding the time required to liquidate positions and the degree of
confidence placed in the accuracy of the volatility and correlation estimates .
The Company's VAR calculation presents a comprehensive market risk disclosure by
combining its commodity derivative portfolio used to hedge price and basis risk
together with the current portfolio of firm physical purchase and sale
31
<PAGE> 32
contracts and nonregulated gas-in-storage inventory. At August 31, 1998, the
Company's estimated potential one-day favorable or unfavorable impact on future
earnings, as measured by the VAR, using a 95 percent confidence level,
diversified correlation and assuming three days to liquidate positions is
immaterial.
The Company's calculated VAR exposure represents an estimate of potential losses
that would be recognized for its portfolio of derivative financial instruments
and firm physical contracts and nonregulated gas-in-storage assuming
hypothetical movements in future market rates and are not necessarily indicative
of actual results that may occur. It does not represent the maximum possible
loss nor any expected loss that may occur, because actual future gains and
losses will differ from those estimated, based on actual fluctuations in the
market rates, operating exposures, and the timing thereof, and changes in the
Company's portfolio of derivative financial instruments and firm physical
contracts.
32
<PAGE> 33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ONEOK, Inc. is responsible for all information included in the
Annual Report whether audited or unaudited. The financial statements have been
prepared in accordance with generally accepted accounting principles, applied in
a consistent manner, and necessarily included some amounts that are based on the
best estimates and judgements of management.
Management maintains a system of internal accounting policies, procedures, and
controls designed to provide reasonable assurance that assets are safeguarded
against loss or unauthorized use and that the financial records are reliable for
preparing financial statements. ONEOK, Inc. maintains an internal auditing staff
responsible for evaluating the adequacy and application of financial and
operating controls and for testing compliance with management's policies and
procedures.
The accompanying consolidated financial statements of ONEOK, Inc. and
subsidiaries as of August 31, 1998 and 1997, and for each of the years in the
three-year period ended August 31, 1998, have been audited by KPMG Peat Marwick
LLP, independent certified public accountants. Their audits include reviews of
the system of internal controls to the extent considered necessary to determine
the audit procedures required to support their opinion on the consolidated
financial statements. The Independent Auditors' Report appears herein.
The Board of Directors performs its oversight role for reviewing the accounting
and auditing procedures and financial reporting of ONEOK, Inc. through its Audit
Committee. Both KPMG Peat Marwick LLP and the Company's internal auditors have
free access to the Committee, without the presence of management, to discuss
accounting, auditing, and financial reporting matters.
33
<PAGE> 34
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders
ONEOK, Inc.:
We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and
subsidiaries as of August 31, 1998 and 1997, and the related consolidated
statements of income, shareholders' equity, and cash flows for each of the
years in the three-year period ended August 31, 1998. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of ONEOK, Inc. and
subsidiaries as of August 31, 1998 and 1997, and the results of their operations
and cash flows for each of the years in the three-year period ended August 31,
1998, in conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Tulsa, Oklahoma
September 18, 1998
34
<PAGE> 35
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Regulated $971,905 $598,390 $538,169
Nonregulated
Marketing 746,800 459,574 598,300
Processing 79,097 71,617 58,395
Production 31,874 27,185 25,479
Other 5,726 5,161 4,002
- ------------------------------------------------------------------------------------------------------
Total Nonregulated 863,497 563,537 686,176
- ------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,835,402 1,161,927 1,224,345
- ------------------------------------------------------------------------------------------------------
Operating Expenses
Cost of gas 1,220,009 725,960 807,694
Operations and maintenance 277,068 210,852 201,644
Depreciation, depletion, and amortization 101,653 74,509 72,868
General taxes 33,217 22,491 21,489
Income taxes 66,585 34,839 33,037
- ------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,698,532 1,068,651 1,136,732
- ------------------------------------------------------------------------------------------------------
Income before Interest 136,870 93,276 87,613
- ------------------------------------------------------------------------------------------------------
Interest
Interest on long-term debt 30,846 31,354 31,748
Other interest 3,723 2,136 2,499
Amortization of debt expense 506 518 530
- ------------------------------------------------------------------------------------------------------
Net Interest 35,075 34,008 34,777
- ------------------------------------------------------------------------------------------------------
Net Income 101,795 59,268 52,836
Preferred Stock Dividends 26,979 285 428
- ------------------------------------------------------------------------------------------------------
Income Available for Common Stock $74,816 $58,983 $52,408
======================================================================================================
Earnings Per Share of Common Stock - Basic $2.44 $2.13 $1.93
======================================================================================================
Earnings Per Share of Common Stock - Diluted $2.23 $2.13 $1.93
======================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
35
<PAGE> 36
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
August 31, 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Assets
Property, Plant, and Equipment
Distribution system $1,527,754 $794,208
Transmission system 577,927 310,231
Gas storage 69,059 55,157
Oil and gas production 327,970 166,337
Gas processing 74,451 86,075
Other 24,769 17,485
- -------------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 2,601,930 $1,429,493
Accumulated depreciation, depletion, and amortization 915,769 586,156
- -------------------------------------------------------------------------------------------------------------------
Net Property 1,686,161 843,337
- -------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 86 14,377
Trade accounts and notes receivable 177,649 100,937
Materials and supplies 10,046 4,303
Gas in storage 128,334 74,027
Advance payments for gas 3,619 3,700
Deferred income taxes 10,094 -
Purchased gas cost adjustment - 1,138
Other current assets 8,245 8,795
- -------------------------------------------------------------------------------------------------------------------
Total Current Assets 338,073 207,277
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Investments 10,505 324
Regulatory assets, net 229,543 144,712
Goodwill 77,422 4,756
Other 80,783 37,001
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 398,253 186,793
- -------------------------------------------------------------------------------------------------------------------
Total Assets $2,422,487 $1,237,407
===================================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
36
<PAGE> 37
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
August 31, 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Liabilities and Shareholders' Equity
Common Shareholder's Equity:
Common stock with $0.01 par value: authorized 100,000,000 shares;
issued and outstanding 31,576,287 shares at August 31, 1998
and 28,079,783 shares at August 31, 1997 $ 316 $ 281
Premium on common stock 329,425 229,522
Retained earnings 270,808 232,823
- -----------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 600,549 462,626
Convertible preferred stock: $0.01 par value, Series A, authorized 100,000,000
shares; issued and outstanding 19,946,448 shares at August 31, 1998 199 -
Convertible preferred stock: $0.01 par value; Series B, authorized 30,000,000
shares; issued and outstanding 83,826 shares at August 31, 1998 1 -
Premium on preferred stock 568,122 -
- -----------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,168,871 462,626
- -----------------------------------------------------------------------------------------------------------------
Long-term debt 312,355 328,214
Current Liabilities:
Current maturities of long-term debt 16,909 18,909
Notes payable 212,000 45,000
Accounts payable 136,601 80,155
Dividends payable 9,007 -
Accrued taxes 16,829 12,996
Accrued interest 7,814 7,376
Customers' deposits 17,042 6,218
Deferred income taxes - 694
Purchased gas cost adjustment 12,168 -
Other 32,443 17,699
- -----------------------------------------------------------------------------------------------------------------
Total Current Liabilities 460,813 189,047
- -----------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 313,955 183,991
Customers' advances for construction
and other deferred credits 166,493 73,529
- -----------------------------------------------------------------------------------------------------------------
Total Deferred Credits 480,448 257,520
- -----------------------------------------------------------------------------------------------------------------
Commitments and Contingencies
- -----------------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $2,422,487 $1,237,407
=================================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
37
<PAGE> 38
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
August 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Net income $ 101,795 $ 59,268 $ 52,836
Depreciation, depletion, and amortization 101,653 74,509 72,868
Net losses of equity investees - 257 173
Deferred income taxes (7,623) (2,988) (2,038)
Other (17,221) - (5,675)
Changes in assets and liabilities
(Increase) decrease in accounts and notes receivable 53,400 18,401 (37,570)
(Increase) decrease in inventories 1,232 13,226 (9,433)
(Increase) decrease in other assets 13,472 (10,096) 8,027
Decrease in regulatory assets - 384 1,431
Increase (decrease) in accounts payable and
accrued liabilities 51,957 (14,897) 33,532
Changes in purchased gas cost adjustment 54,257 10,539 (14,383)
Increase (decrease) in deferred credits
and other liabilities (6,396) 3,448 5,282
- ----------------------------------------------------------------------------------------------------------
Cash Provided by Operating Activities 346,526 152,051 105,050
- ----------------------------------------------------------------------------------------------------------
Investing Activities
Changes in other investments, net (3,778) 1,698 -
Acquisitions, net (24,421) - -
Capital expenditures, net of salvage (301,515) (90,530) (89,582)
Proceeds from sale of property 30,000 - 17,597
- ----------------------------------------------------------------------------------------------------------
Cash Used in Investing Activities (299,714) (88,832) (71,985)
- ----------------------------------------------------------------------------------------------------------
Financing Activities
Issuance (payment) of notes payable, net 5,302 (5,230) (5,052)
Payment of debt (17,859) (14,000) (12,000)
Issuance of common stock 6,257 7,363 -
Dividends paid (54,803) (28,033) (27,914)
Redemption of preferred stock - (9,540) -
- ----------------------------------------------------------------------------------------------------------
Cash Used in Financing Activities (61,103) (49,440) (44,966)
- ----------------------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents (14,291) 13,779 (11,901)
Cash and Cash Equivalents at Beginning of Year 14,377 598 12,499
- ----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 86 $ 14,377 $ 598
==========================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
38
<PAGE> 39
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
<TABLE>
<CAPTION>
Common Shareholders' Equity
----------------------------------------------------------------
Common Premium on Retained Preferred
Stock Common Stock Earnings Total Stock
- --------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at September 1, 1995 $ 270 $ 201,134 $ 187,225 $ 388,629 $ 9,000
Net income -- -- 52,836 52,836 --
Issuance of common stock 2 5,678 -- 5,680 --
Preferred stock dividends -
$2.375 per share -- -- (428) (428) --
Common stock dividends -
$1.18 per share -- -- (32,022) (32,022) --
- --------------------------------------------------------------------------------------------------------------
Balance at August 31, 1996 $ 272 $ 206,812 $ 207,611 $ 414,695 $ 9,000
==============================================================================================================
Balance at September 1, 1996 $ 272 $ 206,812 $ 207,611 $ 414,695 $ 9,000
Net income -- -- 59,268 59,268 --
Issuance of common stock 9 22,710 -- 22,719 --
Preferred stock dividends -
$2.375 per share -- -- (321) (321) --
Redemption of Series A Preferred Stock -- -- (540) (540) (9,000)
Common stock dividends - --
$1.20 per share -- (33,195) (33,195) --
- --------------------------------------------------------------------------------------------------------------
Balance at August 31, 1997 $ 281 $ 229,522 $ 232,823 $ 462,626 --
==============================================================================================================
BALANCE AT SEPTEMBER 1, 1997 $ 281 $ 229,522 $ 232,823 $ 462,626 --
NET INCOME -- -- 101,795 101,795 --
ISSUANCE OF COMMON STOCK
ACQUISITIONS 33 93,648 -- 93,681 --
STOCK PURCHASE PLANS 2 6,255 -- 6,257 --
CONVERTIBLE PREFERRED STOCK DIVIDENDS -
$1.80 AND $1.50 PER SHARE FOR
FOR SERIES A AND B, RESPECTIVELY -- -- (26,979) (26,979) --
ISSUANCE OF SERIES A AND SERIES B
CONVERTIBLE PREFERRED STOCK -- -- -- -- 568,322
COMMON STOCK DIVIDENDS -
$1.20 PER SHARE -- -- (36,831) (36,831) --
- --------------------------------------------------------------------------------------------------------------
BALANCE AT AUGUST 31, 1998 $ 316 $ 329,425 $ 270,808 $ 600,549 $ 568,322
==============================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
39
<PAGE> 40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION - ONEOK, Inc., formerly WAI, Inc. (New ONEOK) is successor
by merger of ONEOK Inc. (Old ONEOK) with and into WAI, Inc. New ONEOK acquired
the gas business of Western Resources, Inc. (Western) and merged with Old ONEOK
on November 26, 1997. The transaction was effective November 30, 1997, for
financial reporting purposes. See Note B of Notes to Consolidated Financial
Statements on page 42.
NATURE OF OPERATIONS - ONEOK, Inc. and subsidiaries (collectively, the Company)
is a diversified energy company engaged in the production, gathering, storage,
transportation, distribution, and marketing of environmentally clean fuels and
products. The Company's business units are characterized as operating within
either a rate regulated environment (regulated operations) or a nonregulated
environment (nonregulated operations). The regulated business units provided
natural gas distribution and transmission to approximately 80 percent of
Oklahoma and 67 percent of Kansas and generated approximately 72 percent of
income before interest and income taxes during 1998. The nonregulated business
has segments involved in various aspects of natural gas marketing, gathering
and processing, and production. The Company's other segment, whose results of
operations are not material, operates and leases the Company's headquarters
building and parking facility.
CONSOLIDATION - The consolidated financial statements include the accounts of
ONEOK, Inc. and its wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation. Investments in
twenty percent to 50 percent-owned affiliates are accounted for on the equity
method. Investments in less than twenty percent owned affiliates are accounted
for on the cost method.
REGULATION - The regulated operations of the Company are primarily subject to
the rate regulation and accounting requirements of the Oklahoma Corporation
Commission (OCC) and of the Kansas Corporation Commission (KCC). Certain other
regulated activities of the Company are subject to regulation by the Federal
Energy Regulatory Commission (FERC). Accordingly, the regulated operations
follow the accounting and reporting guidance contained in Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation." Allocation of costs and revenues to accounting periods for
ratemaking and regulatory purposes may differ from bases generally applied by
nonregulated companies. Such allocations to meet regulatory accounting
requirements are considered to be generally accepted accounting principles for
regulated utilities provided that there is a demonstrable ability to recover any
deferred costs in future rates.
The OCC issued an interim order on July 31, 1998, for ONG to proceed with a
competitive bidding process to obtain some of the upstream services, such as
supply, transportation, and storage, necessary to serve the Oklahoma City
and Tulsa markets. The order outlines how ONG is to proceed with upstream
unbundling. While the Company supports the concept of unbundling, it believes
the order contains elements that are an "invasion of internal management
discretion" and has filed an appeal with the Oklahoma Supreme Court.
During the rate-making process, regulatory commissions may require a utility to
defer recognition of certain costs to be recovered through rates over time as
opposed to expensing such costs as incurred. This allows the utility to
stabilize rates over time rather than passing such costs on to the customer for
immediate recovery. This causes certain expenses to be deferred as a regulatory
asset and amortized to expense as it is recovered through rates. Total
regulatory assets resulting from this deferral process are approximately $230
million and $145 million at August 31, 1998 and 1997 respectively. See Note D of
Notes to Consolidated Financial Statements on page 45.
REVENUE RECOGNITION - The Company recognizes revenue when services are rendered
or product is delivered. Major industrial and commercial gas distribution
customers are invoiced as of the end of each month. Certain gas distribution
customers, primarily residential and some commercial, are invoiced on a cycle
basis throughout the month, and the Company accrues unbilled revenues at the end
of each month. Beginning in 1996, Oklahoma Natural Gas Company's (ONG's) tariff
rates for residential and commercial customers contained a temperature
normalization clause that provided for billing adjustments from actual volumes
to normalized volumes during the winter heating season. Revenues from marketing,
gathering and processing and production are recognized on the sales method.
Credit is granted to these customers under customary terms.
REGULATED PROPERTY - Regulated distribution, transportation, and storage
property is stated at cost. Such cost includes personnel costs, general and
administrative costs, and allowance for funds used during construction. The
allowance for funds used during construction represents the capitalization of
estimated average cost of borrowed funds (8.6 percent, 8.6 percent, and 8.5
percent, in 1998, 1997, and 1996, respectively) used during the construction of
major projects and is recorded as a credit to earnings.
40
<PAGE> 41
Depreciation is calculated using the straight-line method based upon rates
prescribed for ratemaking purposes. The average depreciation rate for OCC
regulated property approximated 3.7 percent in 1998, 3.7 percent in 1997, and
3.6 percent in 1996. The average depreciation rates for KCC regulated properties
in Kansas and Oklahoma were approximately 3.3 percent, and 3.7 percent,
respectively, in 1998. The average depreciation rates for Mid Continent Market
Center (MCMC) properties was 3.4 percent in 1998.
<TABLE>
<CAPTION>
REMAINING SERVICE
LIFE (YEARS)
- -------------------------------------------
<S> <C> <C>
Distribution property 22-25 40
Gathering property 5-33 47
Storage property 5-19 40
Transmission property 18-33 47
Other property 6-24 40
- -------------------------------------------
</TABLE>
Maintenance and repairs are charged directly to expense. Generally, the cost of
property retired or sold, plus removal costs, less salvage, is charged to
accumulated depreciation. Gains and losses from sales or transfers of operating
units or systems are recognized in income.
PRODUCTION PROPERTY - The Company uses the successful-efforts method to account
for costs incurred in the acquisition and exploration of oil and natural gas
reserves. Costs to acquire mineral interests in proved reserves and to drill and
equip development wells are capitalized. Geological and geophysical costs and
costs to drill exploratory wells which do not find proved reserves are expensed.
Unproved oil and gas properties which are individually significant are
periodically assessed for impairment. The remaining unproved oil and gas
properties are aggregated, and an overall impairment allowance is provided based
on the Company's experience.
Depreciation and depletion are calculated using the unit-of-production method
based upon periodic estimates of proven oil and gas reserves. Undeveloped
properties are amortized based upon remaining lease terms and exploratory and
developmental drilling experience.
OTHER PROPERTY - Gas processing plants and all other properties are stated at
cost. Gas processing plants are depreciated using various rates based on
estimated lives of available gas reserves. All other property and equipment is
depreciated using the straight-line method over its estimated useful life.
INVENTORIES - Materials and supplies are priced at average cost. Noncurrent gas
in storage is classified as property and is priced at cost. Cost of current gas
in storage in Oklahoma is determined under the last-in, first-out, (lifo) and
first-in, first-out (fifo) methodology by the regulated and nonregulated
operations, respectively. The estimated replacement cost of current gas in
storage valued under the lifo method was $73.6 million and $63.7 million at
August 31, 1998 and 1997, respectively. The estimated replacement cost of
current gas in storage in Kansas is $33.9 million. Cost of current gas in
storage for Kansas is determined using the weighted average cost of gas method.
INCOME TAXES - Deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates applicable to
future years to differences between the financial statement carrying amounts and
the tax bases of existing assets and liabilities. The effect on deferred taxes
of a change in tax rates is deferred and amortized for the OCC regulated
operations and, for nonregulated operations, is recognized in income in the
period that includes the enactment date. The Company continues to amortize
previously deferred investment tax credits on gas distribution and transmission
properties over the period prescribed by the OCC and KCC for ratemaking
purposes.
COMMODITY PRICE RISK MANAGEMENT - To minimize the risk from market fluctuations
in the price of natural gas and oil, the Company enters into futures
transactions, swaps, and options in order to hedge certain natural gas in
storage, existing physical gas purchases or sales commitments, as well as
anticipated sales of natural gas production. In order to qualify as a hedge, the
price movements in the underlying commodity derivatives must be sufficiently
correlated with the hedged transaction. Changes in the market value of these
financial instruments utilized as hedges are (1) recognized as an adjustment of
the carrying value in the case of existing assets and liabilities, (2) included
in the measurement of the transaction that satisfies the commitment in the case
of existing commitments, and (3) included in the measurement of the subsequent
transaction in the case of anticipated transactions. In cases where anticipated
transactions do not occur, deferred gains and losses are recognized when such
transactions were scheduled to occur. Some of these financial instruments carry
off-balance sheet risks. See in Note C of Notes to Consolidated Financial
Statements on page 43.
IMPAIRMENTS - The Company accounts for the impairment of long-lived assets to be
recognized when indicators of
41
<PAGE> 42
impairment are present and the undiscounted cash flows are not sufficient to
recover the assets carrying amount. The impairment loss is measured by comparing
the fair value of the asset to its carrying amount. Fair values are based on
discounted future cash flows or information provided by sales and purchases of
similar assets. The Company evaluates impairment of production assets on the
lowest possible level, (a field by field basis) rather than using a total
company basis for its proved properties. Primarily due to downward reserve
revisions for certain proven properties, the Company recognized a pre-tax
impairment loss of $8.6 million in 1996, which is included in depreciation,
depletion and amortization expense.
USE OF ESTIMATES - Management has made a number of estimates and assumptions
relating to reporting of assets and liabilities and the disclosure of contingent
assets and liabilities to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could differ from these
estimates.
GOODWILL - The Company amortizes goodwill, which represents the excess of the
purchase price over the fair value of net assets acquired, over a period of 40
years. The Company assesses the recoverability of this intangible asset by
determining whether the amortization of the goodwill balance over its remaining
life can be recovered through undiscounted future operating cash flows of the
acquired operation.
EARNINGS PER COMMON SHARE - In 1998, the Company adopted the provisions of
Statement of Financial Accounting Standards (SFAS) No, 128, Earnings Per Share.
Basic earnings per share are calculated based on the weighted average number of
shares of common stock outstanding during the period. Diluted earnings per share
are calculated based on the weighted average number of shares of common stock
outstanding plus potentially dilutive securities. All prior periods have been
restated to reflect this method of calculation.
ENVIRONMENTAL EXPENDITURES - The Company accrues for losses associated with
environmental remediation obligations when such losses are probable and
reasonably estimatable. Accruals for estimated losses from environmental
remediation obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as further information
develops or circumstances change. Recoveries of environmental remediation costs
from other parties are recorded as assets when their receipt is deemed probable.
CASH AND CASH EQUIVALENTS - Cash equivalents consist of highly liquid
investments, which are readily convertible into cash and have original
maturities of three months or less.
COMMON STOCK OPTIONS AND AWARDS -The Company adopted SFAS No. 123, "Accounting
for Stock-Based Compensation" which permits, but does not require, a fair value
based method of accounting for stock-based employee compensation. Alternatively,
SFAS No. 123 allows companies to continue applying the provisions of Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"), however, such companies are required to disclose pro forma net
income and earnings per share as if the fair value based method had been
applied. The Company has elected to continue to apply the provisions of APB 25
for purposes of computing compensation expense and has provided the pro forma
disclosure provisions of SFAS No. 123 in Note N of Notes to Consolidated
Financial Statements on page 53.
RECLASSIFICATION. Certain amounts in the 1997 consolidated financial statements
have been reclassified to conform with the 1998 presentation.
(B) ACQUISITIONS
On November 26, 1997, Old ONEOK acquired from Western all of the assets of
Western that were primarily used in, or primarily related to or primarily
generated by, the field operations of the local natural gas distribution
business of Western, and all of the outstanding capital stock of Western's
directly or indirectly wholly-owned subsidiaries, Westar Gas Marketing, Inc. and
MCMC, and assumed (i) all of the liabilities of Western that arose primarily out
of or related primarily to or were primarily generated by gas business and (ii)
approximately $161 million in aggregate principal amount of debt of Western; and
Old ONEOK merged (the "Merger") with an into New ONEOK, with New ONEOK as the
surviving corporation. The shares of Old ONEOK common stock were converted on
a one-for-one basis into shares of stock of New ONEOK, and Western received
2,996,702 shares of the Company's Common Stock and 19,317,584 shares of the
Company's Series A Convertible Preferred Stock. Such shares and additional
shares purchased
42
<PAGE> 43
by Western at the closing of the transaction represented in the aggregate 9.9
percent of the outstanding Common Stock or 45 percent of the Capital Stock of
the Company. A shareholder agreement, which includes standstill provisions,
prevents Western from increasing its position in the Company above a common
stock interest of 45 percent on a fully converted basis and maintains control of
the Company in the hands of the public shareholders of the Company.
The acquisition was accounted for as a purchase and, accordingly, the operating
results of the properties acquired from Western are included in the consolidated
financial statements since December 1, 1997. The aggregate purchase price was
approximately $824 million, including debt assumed and transaction costs. The
aggregate purchase price, which was funded through the issuance of a combination
of preferred and common stock, was allocated based on the estimated fair value
of the net assets. The excess of the purchase price over the fair value of the
net assets acquired approximated $74 million and is being amortized over 40
years.
The Company acquired Washita Production Company, a Tulsa based independent oil
and gas producer, in December 1997. For financial statement purposes the
transaction was accounted for as a purchase and, accordingly, the operating
results of Washita are included in the consolidated financial statements since
the date of acquisition. The aggregate purchase price of $20 million was made
with a combination of the Company's common stock and cash.
In June 1998, the Company acquired a 40 percent equity interest in K. Stewart
Petroleum Corp. increasing the Company's interest in oil and gas reserves
located in the Anadarko Basin. The $6.0 million acquisition was made with a
combination of the Company's common stock and cash.
The table of unaudited pro forma information presents a summary of consolidated
results of operations of the Company as if the acquisition of the gas business
from Western had occurred at the beginning of fiscal 1997. These results do not
necessarily reflect the results which would have been obtained if the merger had
actually occurred on the dates indicated or the results which may be expected in
the future.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
Pro Forma
(Thousands of dollars -------------------------
except per share amounts) 1998 1997
- -------------------------------------------------------------------------
<S> <C> <C>
Total operating revenues $2,034,640 $2,011,134
Income before interest and income taxes $207,281 $183,202
Net income $104,185 $86,310
Preferred stock dividends $35,955 $35,955
Income available for common stock $68,230 $50,355
Earnings per share of common stock - basic $2.17 $1.64
Earnings per share of common stock - diluted $2.03 $1.64
- -------------------------------------------------------------------------
</TABLE>
(C) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
FINANCIAL INSTRUMENTS - The following table presents the carrying amounts and
fair values of certain of the Company's financial instruments. Fair value is
defined as the amount at which the instrument could be exchanged in a current
transaction between willing parties. The estimated fair value of long-term debt
and notes payable has been determined using quoted market prices of same or
similar issues, discounted cash flows, and/or rates currently available to the
Company for debt with similar terms and remaining maturities. The fair value of
natural gas and oil swaps, options, and futures contracts generally reflect the
estimated amounts that the Company would pay or receive to terminate the
contracts at the reporting date, thereby taking into account the unrealized
gains and losses on open contracts. There is no readily available market for
natural gas swaps. The items presented without a carrying value are off-balance
sheet financial instruments. All of the Company's financial instruments are held
for purposes other than trading.
43
<PAGE> 44
<TABLE>
<CAPTION>
- -----------------------------------------------------------
Approximate
(Thousands of Dollars) Book Value Fair Value
- -----------------------------------------------------------
<S> <C> <C>
AUGUST 31, 1998
Cash and cash equivalents $86 $86
Accounts and notes receivable $177,139 $177,139
Natural gas swaps - $750
Natural gas options - $3,486
Natural gas futures - $9,971
Notes payable $212,000 $212,000
Long-term debt $329,264 $358,207
- -----------------------------------------------------------
August 31, 1997
Cash and cash equivalents $14,377 $14,377
Accounts and notes receivable $100,937 $100,937
Natural gas swaps - $3,809
Natural gas options - ($273)
Natural gas futures - ($1,700)
Notes payable $ 45,000 $ 45,000
Long-term debt $347,123 $379,141
- -----------------------------------------------------------
</TABLE>
Risk Management - The Company's gas marketing, gathering and processing, and
production operations subject the Company's earnings to variability based on
fluctuations in both the market price and transportation costs of natural gas
and oil. The Company's exposure arises from fixed price purchase or sale
agreements which extend for periods of up to 48 months, certain gas storage
inventories, and anticipated sales of oil and gas production. In order to
mitigate the financial risks associated with such activities, the Company
routinely enters into natural gas and oil futures contracts, swaps, and options,
collectively referred to herein as derivatives. Net open positions in terms of
price, volume, and specified delivery point do occur.
The futures contracts are purchased and sold on the New York Mercantile Exchange
(NYMEX) or the Kansas City Board of Trade (KCBOT) and require the Company to buy
or sell natural gas at a fixed price. Swap agreements generally require one
party to make payments based on the difference between a fixed price or fixed
differential from the NYMEX or KCBOT price while the other party pays a price
based on a published index. Swaps and options allow the Company to commit to
purchase gas at one location and sell it at another location without assuming
unacceptable risk with respect to changes in the price of gas or the cost of the
intervening transportation. Natural gas options held to hedge price risk provide
the right, but not the requirement, to buy or sell natural gas at a fixed price.
The Company utilizes options to limit overall price risk exposure. None of these
derivatives are held for speculative purposes and, in general, the Company's
risk management policy requires that positions taken with derivatives be offset
by positions in physical transactions or other derivatives.
<TABLE>
<CAPTION>
- ------------------------------------------------------------
(VOLUMES IN MMcF, ESTIMATED FAIR
THOUSANDS OF DOLLARS) VOLUMES VOLUMES MARKET VALUE
AUGUST 31, 1998 PURCHASED SOLD GAIN (LOSS) (A)
- ------------------------------------------------------------
<S> <C> <C> <C>
OPTIONS 4,543 2,536 $3,486
SWAPS 49,281 44,715 $750
FUTURES 5,375 35,492 $9,971
- ------------------------------------------------------------
August 31, 1997
- ------------------------------------------------------------
Options 2,000 11,960 ($ 273)
Swaps 72,414 62,908 $3,809
Futures 30,420 32,010 ($1,700)
- ------------------------------------------------------------
</TABLE>
The notional value of futures contracts purchased and sold is $7.6 million and
$82.5 million, respectively, at August 31, 1998. The term "notional amount"
refers to the current contract unit price times the contract volume for the
relevant derivative. In general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative of the Company's level of activity in such derivatives,
although the amounts at risk are significantly smaller because, in general,
changes in market value of these derivatives are offset by changes in the value
associated with the underlying physical transaction or other derivatives.
(A) represents the estimated amount which would have been recognized upon
termination of the relevant derivatives as of the date indicated. The amount
which is ultimately charged or credited to earnings is affected by subsequent
changes in the market value of these derivatives.
NYMEX- and KCBOT-traded futures and option
44
<PAGE> 45
contracts are guaranteed by NYMEX and KCBOT and have nominal credit risk. All
other derivative transactions expose the Company to off-balance sheet risk in
the event of non performance by the counterparts. In order to minimize this
risk, the Company analyzes each counterpart's financial condition prior to
entering into an agreement, establishes credit limits, and monitors the
appropriateness of these limits on an on-going basis. Swap agreements are
generally settled at the expiration of the contract term and may be subject to
margin requirements with the counterparty. NYMEX- and KCBOT-traded futures and
options contracts require daily cash settlement in margin accounts with brokers.
(D) REGULATORY ASSETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------
AUGUST 31, 1998 1997
(Thousands of Dollars)
- -----------------------------------------------------------
<S> <C> <C>
Recoupable take-or-pay $90,708 $95,482
Pension costs 25,061 29,244
Postretirement costs other than pension 59,963 8,836
Other 8,917 3,327
Transition costs 18,447 -
Income taxes 26,447 7,823
- -----------------------------------------------------------
Regulatory Assets, Net $229,543 144,712
===========================================================
</TABLE>
The table presents a summary of regulatory assets, net of amortization,
outstanding at August 31, 1998, and August 31, 1997.
Certain of the regulatory assets including a portion of Kansas Gas Service net
deferred income taxes and the assets listed in the table below, are being
recovered through rates, but the Company is not being allowed to earn a rate of
return on the unrecovered balance. The remaining recovery period for these
assets is set forth in the table below.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------
REMAINING RECOVERY
PERIOD (MONTHS)
- ------------------------------------------------------------------------
<S> <C>
Postretirement costs other than pension - Oklahoma 181
Income taxes - Oklahoma 154 - 170
Transition Costs 480
- ------------------------------------------------------------------------
</TABLE>
No significant recoupable costs attributable to resolutions of take-or-pay and
pricing issues were incurred in 1998 or 1997. The OCC has authorized recovery of
the take-or-pay settlement costs through a combination of a surcharge to
customers and revenues derived from certain transportation customers.
ONG's pension and postretirement benefit costs previously deferred are currently
being recovered through revenue and are being amortized to expense over a 10 to
18 year period. As discussed in Note H, the OCC also approved recovery of
pension and post retirement costs through rates.
Kansas Gas Service has been deferring and recording postretirement benefits in
excess of pay-as-you-go as a regulatory asset. See Note H of Notes to
Consolidated Financial Statements on page 47.
The KCC has allowed certain transition costs to be amortized and recovered in
rates over a forty year period with no rate of return on the unrecovered
balance. Management believes that all transition costs recorded as a regulatory
asset will be recovered through rates based on the accounting orders received
and regulatory precedents established by the KCC.
In accordance with various rate orders received from the KCC and the OCC, Kansas
Gas Service has not yet collected through rates the amounts necessary to pay a
significant portion of the net deferred income tax liabilities. As management
believes it is probable that the net future increases in income taxes payable
will be recovered from customers, it has recorded a regulatory asset for these
amounts.
45
<PAGE> 46
Amortization expense related to regulatory assets was approximately $11.4
million, $10.1 million, and $11.7 million in 1998, 1997, and 1996, respectively.
(E) CAPITAL STOCK
The Company has approximately 68 million shares of unrestricted common stock
available for issue. The Company redeemed all of its outstanding shares of
Series A Preferred Stock, par value $50 per share, at its stated voluntary
liquidation value of $53 per share during the third quarter of fiscal 1997. The
Company issued Series A Convertible Preferred Stock, par value $0.01 per share,
at the time of the alliance with Western. The holders of Series A Convertible
Preferred Stock are entitled to receive a dividend payment, with respect to each
dividend period of the common stock, equal to 1.5 times the dividend amount
declared in respect of each share of common stock. The terms of Series B
Convertible Preferred Stock are the same as Series A Convertible Preferred
Stock, except that the dividend amount is equal to 1.25 times the common stock
dividend. Series C Preferred Stock is designed to protect ONEOK, Inc.
shareholders from coercive or unfair takeover tactics. Holders of Series C
Preferred Stock are entitled to receive, in preference to the holders of ONEOK
common stock, quarterly dividends in an amount per share equal to the greater of
$1 or subject to adjustment, 100 times the aggregate per share amount of all
cash dividends, and 100 times the aggregate per share amount of all non-cash
dividends. No Series C Preferred Stock has been issued.
The Series A and Series B Convertible Preferred Stock is convertible, subject to
certain restrictions, at the option of the holder, into ONEOK, Inc., Common
Stock at the rate of one share for each share of Series A or Series B
Convertible Preferred Stock.
In connection with the merger transaction with WAI, Inc., the common stock of
Old ONEOK, no par value, was exchanged for the common stock of New ONEOK, $0.01
par value, on a one-for-one basis. See Note B. As a result of the share
exchange, all common share data has been adjusted retroactively in the
accompanying consolidated financial statements.
The Board of Directors has reserved 3.0 million shares of ONEOK, Inc's common
stock for the Direct Stock Purchase and Dividend Reinvestment Plan of which 142
thousand shares were issued in 1998 and 363 thousand shares were issued in 1997;
and has reserved approximately 3.6 million shares for the Thrift Plan for
Employees of ONEOK, Inc. and Subsidiaries, excluding Kansas Gas Service Company
(KGS) employees and 3.6 million shares for the Thrift Plan for Employees of KGS.
Under the most restrictive covenants of the Company's loan agreements, $243.1
million (89.9 percent) of retained earnings at August 31, 1998, was available to
pay dividends.
(F) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE
At August 31, 1998, the Company had a short-term unsecured credit agreement with
several banks pursuant to which the banks have agreed to make loans to the
Company from time to time in an aggregate amount not to exceed $200 million at
any one time for general corporate purposes. The short-term credit agreement
provides a back-up line of credit for short-term debt from other sources in
addition to providing short-term funds. The facility fee requirement for this
line of credit is .06 percent applied annually to the total line of credit.
Borrowing under the agreement bears interest at offshore IBOR rates plus .19
percent per annum. No compensating balance requirements existed at August 31,
1998. The Company also has additional credit facilities available through a
master note with Bank of America which provides an additional $30 million in
borrowing capability. Maximum short-term debt from all sources as approved by
the Company's Board of Directors is $225 million.
Short-term notes payable totaling $212 million at August 31, 1998, and $45
million at August 31, 1997, were outstanding. The notes carried average interest
rates of 5.83 percent and 5.84 percent, respectively.
46
<PAGE> 47
(G) LONG-TERM DEBT
All long-term notes payable at August 31, 1998, are unsecured. The aggregate
current maturities of long-term debt for each of the five years ending August
31, 2003, are $16.9 million; $16.8 million; $15.4 million; $14.7 million; and
$14.7 million, respectively, including $1.1 million each year callable at the
option of the holder.
<TABLE>
<CAPTION>
- -------------------------------------------
AUGUST 31, 1998 1997
(THOUSANDS OF DOLLARS)
- -------------------------------------------
Long-term Notes Payable
<S> <C> <C>
5.90% due 1998 $0 $10,000
6.20% due 1999 8,000 8,000
6.43% due 2000 5,000 5,000
6.75% due 2001 5,393 9,252
8.32% due 2007 36,000 40,000
8.44% due 2004 40,000 40,000
8.70% due 2021 34,871 34,871
9.70% due 2019 125,000 125,000
9.75% due 2020 75,000 75,000
- -------------------------------------------
Total $329,264 $347,123
- -------------------------------------------
Current maturities of
long-term debt 16,909 18,909
- -------------------------------------------
Long-term notes payable $312,355 $328,214
- -------------------------------------------
</TABLE>
(H) EMPLOYEE BENEFITS PLANS
RETIREMENT PLANS - The Company has defined benefit retirement plans covering
substantially all employees. Company officers and certain key employees are also
eligible to participate in supplemental retirement plans.
Net pension costs under the plans, as determined by an independent actuary,
consists of the following:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------
AUGUST 31, 1998 1997 1996
(THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------
<S> <C> <C> <C>
Service cost $7,221 $5,126 5,957
Interest cost 30,875 23,766 $23,525
Actual return on assets (114,514) (9,010) (72,138)
Net amortization and deferral 75,684 (16,281) 50,337
- ---------------------------------------------------------------
Net pension cost (benefit) ($734) $3,601 $7,681
===============================================================
</TABLE>
The Company generally funds pension costs at a level equal to the minimum amount
required under the Employee Retirement Income Security Act of 1974. The
accompanying table sets forth the funded status of the Company's plans, as
determined by the independent actuary.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
AUGUST 31, 1998 1997
(THOUSANDS OF DOLLARS)
- -----------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of vested benefit obligation ($413,195) ($277,266)
Accumulated benefit obligation (440,892) (291,662)
Projected benefit obligation (500,327) (326,539)
Plan assets at fair value, principally equity
securities and an IPG fund 595,308 326,384
- -----------------------------------------------------------------------------
Plan assets more (less) than projected
benefit obligation 94,981 (155)
Unrecognized net loss (gain) (30,388) 15,308
Unrecognized prior service cost 607 784
Unrecognized net asset (2,805) (3,272)
- -----------------------------------------------------------------------------
Prepaid pension cost $62,395 $12,665
=============================================================================
</TABLE>
47
<PAGE> 48
The projected benefit obligation was determined using an annual discount rate of
6.75 percent for 1998 and 7.75 percent for 1997; a long-term return on plan
assets of 9 percent for both 1998 and 1997; and an average assumed long-term
annual rate of salary increases of 4 to 4.5 percent for 1998 and 4 percent for
1997.
OTHER POSTRETIREMENT BENEFIT PLANS - The Company sponsors welfare care plans
that provide postretirement medical benefits and life and accidental death and
dismemberment benefits to substantially all employees who retire under the
Retirement Plans at age 55 or older with at least five years of service. The
plans are contributory, with retiree contributions adjusted periodically, and
contain other cost-sharing features such as deductibles and coinsurance.
The Company elected to delay recognition of the accumulated postretirement
benefit obligation (APBO) of approximately $72.2 million and amortize it over 20
years as a component of net periodic postretirement benefit cost.
Net periodic postretirement benefit cost includes the following components:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
AUGUST 31, 1998 1997 1996
(THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $2,570 $1,744 $ 1,704
Interest cost 8,224 5,599 5,668
Actual return on assets (1,646) (184) --
Net amortization and deferral 3,916 3,387 3,608
- ----------------------------------------------------------------------
Net periodic postretirement benefit cost $13,064 $10,546 $10,980
======================================================================
</TABLE>
For measurement purposes, a 7.75 percent annual rate of increase in the per
capita cost of covered medical benefits (i.e., medical cost trend rate) was
assumed for 1998, the rate was assumed to decrease gradually to 5 percent by the
year 2003 and remain at that level thereafter. The medical cost trend rate
assumption has a significant effect on the amounts reported. For example,
increasing the assumed medical cost trend by one percentage point in each year
would increase the accumulated postretirement benefit obligation as of August
31, 1998, by $10.6 million and the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for the year ended August
31, 1998, by $0.9 million.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 6.75 percent and 7.75 percent at August
31, 1998, and 1997 respectively.
The following table presents the plans' funded status as determined by the
independent actuary.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
AUGUST 31, 1998 1997
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees ($90,099) ($49,840)
Fully eligible active plan participants (11,115) (3,192)
Other active plan participants (52,112) (22,074)
- --------------------------------------------------------------------
Accumulated postretirement benefit obligations (153,326 (75,106)
Fair value of plan assets 14,075 8,150
- --------------------------------------------------------------------
Accumulated postretirement benefit obligations
in excess of plan assets (139,251) (66,956)
Unrecognized transition obligation 48,522 51,757
Unrecognized net (gain) loss 18,095 (5,307)
- --------------------------------------------------------------------
Accrued postretirement benefit costs ($72,634) ($20,506)
====================================================================
</TABLE>
EMPLOYEE THRIFT PLANS - The Company has Thrift Plans covering substantially all
employees. Employee contributions are discretionary. Subject to certain limits,
employee contributions are matched by the Company. The annual cost of the plans
was $4.7 million in 1998; $3.4 million in 1997; $3.7 million in 1996.
POSTEMPLOYMENT BENEFITS - The Company pays postemployment benefits to former or
inactive employees after employment but before normal retirement.
48
<PAGE> 49
REGULATORY TREATMENT - The OCC has approved the recovery of ONG pension costs
and other postretirement benefit costs through rates. The costs recovered
through rates are based on current funding requirements and the net periodic
postretirement benefit cost for pension and postretirement costs, respectively.
Differences, if any, between the expense and the amount ordered through rates
are charged to earnings.
Prior to the acquisition of the Kansas regulated properties in fiscal 1998
Western had established a corporate-owned life insurance ("COLI") program which
it believed in the long term would offset the expenses of its postretirement and
postemployment benefit plans. Accordingly, the KCC issued an order permitting
the deferral of postretirement and postemployment benefit expenses in excess of
amounts recognized on a pay-as-you-go basis. The Company did not acquire the
COLI program. In connection with the KCC's approval of the acquisition, the KCC
granted the Company the benefit of all previous accounting orders issued to
Western and requested that the Company submit a plan of recovery either through
a general rate increase or through specific cost savings or revenue increases.
Based on regulatory precedents established by the KCC, and the accounting order
which permits the Company to seek recovery through rates, management believes
that it is probable that accrued postretirement and postemployment benefits can
be recovered in rates. The Company plans to file for recovery of these costs and
anticipates that recovery will be allowed over a period not to exceed 20 years.
If these costs can not be recovered in rates charged to customers, the Company
would be required to record a one-time charge to expense the regulatory asset
established for postretirement and postemployment benefit costs totaling
approximately $51.6 million at August 31, 1998.
(I) COMMITMENTS AND CONTINGENCIES
LEASES - The initial term of the Company's headquarters building, ONEOK Plaza,
is for 25 years, expiring in 2009, with six five-year renewal options. At the
end of the initial term or any renewal period, the Company can purchase the
property at its fair market value. Rent for the lease accrues annually at $6.8
million until 2009. Rent payments were $5.8 million for 1998, 1997, and 1996.
Estimated future minimum rental payments for the lease are $5.8 million for the
year ended August 31, 1999, $7.6 million for the year ending August 31, 2000,
and $9.3 million for each of the years ending August 31, 2001 through 2009.
The Company has the right to sublet excess office space in ONEOK Plaza. The
Company received $2.8 million, $2.7 million, and $2.5 million in rental revenue
during 1998, 1997, and 1996, respectively, for various subleases. Estimated
minimum future rental payments to be received under existing contracts for
subleases are $2.4 million in 1999, $2.1 million in 2000, $2.0 million in 2001,
$1.9 million in 2002, $1.6 million in 2003, and a total of $2.2 million
thereafter.
Other operating leases include automotive fleets and office building and
equipment. The total estimated payments for these leases are $1.4 million in
1999, $1.0 million in 2000, and $0.8 million in 2001 through 2003.
ENVIRONMENTAL - In connection with the Western transaction, the Company acquired
12 manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials that are classified as hazardous material.
Hazardous materials are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the Kansas
Department of Health and Environment (KDHE) presently governs all future work at
these sites. The terms of the consent agreement allow the Company to investigate
these sites and set remediation priorities based upon the results of the
investigations and risk analysis. The prioritized sites will be investigated
over a ten year period. At August 31, 1998, the costs of the investigations and
risk analysis have been minimal. Limited information is available about the
sites and no testing has been performed. Management's best estimate of the cost
of remediation ranges from $100 thousand to $10 million per site based on a
limited comparison of costs incurred to remediate comparable sites. These
estimates do not give effect to potential insurance recoveries, recoveries
through rates or from third parties. The KCC has permitted others to recover
their remediation costs through rates. It should be noted that additional
information and testing could result in costs significantly below or in excess
of the amounts estimated above. To the extent that such remediation costs are
not recovered, the costs could be material to the Company's results of
operations and cash flows depending on the degree of remediation required and
number of years over which the remediation must be completed.
OTHER - The Company is a party to other litigation matters and claims which are
normal in the course of its operations, and while the results of litigation and
claims cannot be predicted with certainty, management believes the final outcome
49
<PAGE> 50
of such matters will not have a materially adverse effect on consolidated
results of operations, financial position, or liquidity.
(J) INCOME TAXES
The provisions for income taxes are as follows:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Current income taxes
Federal 62,462 $32,207 $29,925
State 11,746 5,620 5,150
- ---------------------------------------------------------------------
Total current income taxes 74,208 $37,827 $35,075
=====================================================================
Deferred income taxes
Federal (6,325) ($2,551) ($1,766)
State (1,298) (437) (272)
- ---------------------------------------------------------------------
Total deferred income taxes (7,623) ($2,988) ($2,038)
=====================================================================
Total provision for income taxes 66,585 $34,839 $33,037
=====================================================================
</TABLE>
Following is a reconciliation of the provision for income taxes.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Pretax income 168,380 $94,107 $85,874
Federal statutory income tax rate 35.0% 35.0% 35.0%
- ----------------------------------------------------------------------------------------
Provision for federal income taxes 58,933 $32,937 $30,056
Amortization of distribution property investment tax credit (938) (655) (727)
State income taxes, net of credits and federal tax benefit 5,693 2,376 3,548
Other, net 2,897 181 160
- ----------------------------------------------------------------------------------------
Actual income tax expense 66,585 $34,839 $33,037
========================================================================================
</TABLE>
The tax effects of temporary differences that gave rise to significant portions
of the deferred tax assets and liabilities are shown in the accompanying table.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
AUGUST 31, 1998 1997
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------
<S> <C> <C>
Deferred tax assets
Accrued liabilities not deductible until paid 6,089 5,629
Net operating loss carry forward 854 760
Regulatory assets 4,894 2,687
Other - 2,791
- --------------------------------------------------------------------------
Total deferred tax assets 11,837 11,867
Valuation allowance for net operating loss
carryforward expected to expire prior to
utilization 854 760
- --------------------------------------------------------------------------
Net deferred tax assets 10,983 11,107
Deferred tax liabilities
Excess of tax over book depreciation and depletion 220,064 138,312
Investment in joint ventures 4,543 1,100
Regulatory assets 77,454 53,683
Other 12,783 2,698
- --------------------------------------------------------------------------
Gross deferred tax liabilities 314,844 195,793
- --------------------------------------------------------------------------
Net deferred tax liabilities 303,861 $184,686
==========================================================================
</TABLE>
The Company has remaining net operating loss carry-forwards for state income tax
purposes of approximately $15.8
50
<PAGE> 51
million at August 31, 1998, which expire, unless previously utilized, at various
dates through the year 2009. At August 31, 1998, the Company had $9.6 million in
deferred investment tax credits recorded in other deferred credits which will be
amortized over the next 17 years.
(K) SEGMENT INFORMATION
The Company conducts its business through five reporting segments: (1)
Regulated, which includes gathering, transportation, storage, and distribution
of natural gas, transportation of gas for others, and leasing pipeline capacity;
(2) Marketing, which purchases and markets natural gas; (3) Gathering and
Processing, which includes extracting and selling natural gas liquids; (4)
Production, which includes exploiting, producing, and selling natural gas and
oil; and (5) Other, which includes operating and leasing the Company's
headquarters building and a related parking facility.
Following is information relative to the Company's operations in different
segments.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
1998 Gathering &
(Millions of Dollars) Regulated Marketing Processing Production Other Total
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Sales to unaffiliated customers $971.9 $746.8 $79.1 $31.9 $5.7 $1,835.4
Intersegment sales 22.8 31.8 15.4 12.7 18.7 101.4
- ---------------------------------------------------------------------------------------------------------------
Total Revenues $994.7 $778.6 $94.5 $44.6 $24.4 $1,936.8
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before interest and income taxes $149.4 $12.3 $31.0 $10.9 ($0.1) $203.5
Indentifiable assets $1,931.9 $123.9 $63.2 $246.1 ($57.4) $2,422.5
Depreciation, depletion, and amortization $79.0 $0.6 $2.2 $18.9 $0.9 $101.6
Capital expenditures $113.8 $0.0 $18.4 $167.7 $6.5 $306.4
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
1997 Gathering &
(Millions of Dollars) Regulated Marketing Processing Production Other Total
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Sales to unaffiliated customers $598.4 $459.6 $71.6 $27.2 $5.1 $1,161.9
Intersegment sales 1.1 23.5 15.5 14.0 5.2 59.3
- ---------------------------------------------------------------------------------------------------------------
Total Revenues $599.5 $483.1 $87.1 $41.2 $10.3 $1,221.2
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before interest and income taxes $100.4 $7.8 $12.9 $8.7 ($1.0) $128.8
Indentifiable assets $1,026.3 $63.8 $36.0 $100.1 $11.2 $1,237.4
Depreciation, depletion, and amortization $51.4 $0.5 $2.4 $19.9 $0.3 $74.5
Capital expenditures $67.7 $0.4 $10.6 $32.9 $0.4 $112.0
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
1996 Gathering &
(Millions of Dollars) Regulated Marketing Processing Production Other Total
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Sales to unaffiliated customers $538.2 $598.3 $58.4 $25.5 $4.0 $1,224.4
Intersegment sales 2.2 15.5 12.7 7.9 5.4 43.7
- ---------------------------------------------------------------------------------------------------------------
Total Revenues $540.4 $613.8 $71.1 $33.4 $9.4 $1,268.1
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before interest and income taxes $97.3 $12.9 $9.0 $2.8 ($1.0) $121.0
Indentifiable assets $1,019.4 $71.2 $26.7 $73.2 $29.4 $1,219.9
Depreciation, depletion, and amortization $50.8 $0.5 $2.0 $19.2 $0.4 $72.9
Capital expenditures $42.9 $0.4 $5.2 $46.7 $0.2 $95.4
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
51
<PAGE> 52
(L) QUARTERLY FINANCIAL DATA (UNAUDITED)
Total operating revenues are consistently greater from November through May due
to the large volume of natural gas sold to customers for heating. A summary of
the unaudited quarterly results of operations for 1998 and 1997 follows:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Quarter
1998 -------------------------------------------
(Thousands of Dollars, Except Per Share Amounts) First Second Third Fourth
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues
Regulated $118,637 $470,314 $256,434 $126,520
Nonregulated $195,523 $251,740 $187,614 $228,620
Income before interest and income taxes $21,048 $84,638 $32,780 ($1,596)
Income taxes $7,438 $46,611 $17,270 ($4,734)
Net income (loss) $12,520 $73,836 $26,936 ($11,497)
Earnings (loss) per share of common stock - basic $0.44 $2.06 $0.57 ($0.65)
Earnings (loss) per share of common stock - diluted $0.44 $1.43 $0.52 ($0.65)
Dividends per share of common stock $0.30 $0.30 $0.30 $0.30
Average shares of common stock
outstanding (thousands) - basic 28,268 31,466 31,536 31,586
Average shares of common stock
outstanding (thousands) - diluted 28,268 51,576 51,589 31,586
- ---------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Quarter
1997 -------------------------------------------
(Thousands of Dollars, Except Per Share Amounts) First Second Third Fourth
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues
Regulated $113,246 $282,794 $128,970 $73,380
Nonregulated $135,506 $190,859 $102,657 $134,515
Income before interest and income taxes (loss) $28,678 $71,057 $29,924 ($867)
Income taxes $7,665 $23,818 $8,174 ($4,816)
Net income (loss) $12,174 $38,241 $13,769 ($4,916)
Earnings (loss) per share of common stock - basic and
diluted $0.44 $1.39 $0.49 ($0.19)
Dividends per share of common stock $0.30 $0.30 $0.30 $0.30
Average shares of common stock
outstanding (thousands) - basic and diluted 27,305 27,378 27,897 28,018
- ---------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Cash paid during the year
Interest (including amounts capitalized) $34,637 $39,993 $35,122
Income taxes $73,772 $34,618 $40,642
Noncash transactions:
Gas received as payment in kind $280 $478 $2,395
Issuance of common stock related to:
Stock Performance Plan - - $1,144
Dividend reinvestment plan - $5,482 $4,536
Distribution of net assets from partnership - - $14,625
Acquisitions
Plant, property and equipment $642,742 - -
Current assets $232,738 - -
Current liabilities ($42,575) - -
Debt assumed ($161,698) - -
Regulatory assets and goodwill $169,983 - -
Deferred debits $62,633 - -
Deferred credits ($89,655) - -
Deferred income taxes ($127,744) - -
Capital stock ($662,003)
----------
Cash paid $24,421 - -
=============================================================================
</TABLE>
(M) SUPPLEMENTAL CASH FLOW INFORMATION
The table presents supplemental information relative to the Company's cash flows
for the years ended August 31, 1998, 1997, and 1996.
52
<PAGE> 53
(N) STOCK BASED COMPENSATION
KEY EMPLOYEE STOCK PLAN - On August 17, 1995, the Company adopted the Key
Employee Stock Plan (Plan). The Plan provides for the granting of incentive
stock options, fixed stock options, and stock bonus awards to key employees.
Under the Plan, options may be granted by the Executive Compensation Committee
(the Committee) at any time within ten years thereafter (before August 17,
2005). Options may be granted which are not exercisable until a fixed future
date or in installments. The Plan also provides for restored options in the
event that the optionee surrenders shares of common stock which the optionee
already owns in full or partial payment of the options price under this option
and/or surrenders shares of common stock to satisfy withholding tax obligations
incident to the exercise of this option. A restored option has an option price
equal to the fair market value of the common stock on the date on which the
exercise of the option resulted in the grant of the restored option. The Company
has reserved one million shares of common stock for the Plan.
<TABLE>
<CAPTION>
- ----------------------------------------------------
Number Weighted Average
Of Shares Exercise Price
- ----------------------------------------------------
<S> <C> <C>
Outstanding at
September 1, 1995 0 $0.00
Granted 107,400 $23.69
- ----------------------------------------------------
Outstanding at
August 31, 1996 107,400 $23.69
Granted 100,700 $26.88
Exercised (20,700) $23.69
Expired (2,200) $26.69
Restored 4,147 $30.71
- ----------------------------------------------------
Outstanding at
August 31, 1997 189,347 $25.54
Granted 262,576 $33.39
Exercised (96,047) $25.55
Expired (4,900) $33.94
- ----------------------------------------------------
Outstanding at
August 31, 1998 350,976 $31.30
- ----------------------------------------------------
</TABLE>
Options issued to date become void upon voluntary termination of employment
other than retirement. In the event of retirement or involuntary termination,
the optionee may exercise the option within three months. In the event of death,
the option may be exercised by the personal representative of the optionee
within a period to be determined by the Committee and stated in the option.
Options issued to date can be exercised after one year from grant date and must
be exercised no more than ten years after grant date. Activity to date has been
as follows:
At August 31, 1998, the Company had 92,800 outstanding options with exercise
prices ranging between $23.69 to $29.81 and a weighted average remaining life of
7.72 year, respectively. All of these options were exercisable at August 31,
1998 with a weighted average exercise price of $25.52.
The Company also had 258,176 option outstanding at August 31, 1998 with exercise
prices ranging between $32.41 and $42.53 and a weighted average remaining
contractual life of 9.05 years. Of these options, 1,669 were exercisable at
August 31, 1998 at a price of $40.25.
EMPLOYEE STOCK PURCHASE PLAN - In 1995, the Company authorized the Employee
Stock Purchase Plan and reserved 350,000 shares of common stock for it. Almost
all full-time employees are eligible to participate. Under the terms of the
plan, employees can choose to have up to ten percent of their annual earnings
withheld to purchase the Company's common stock. The Committee may allow
contributions to be made by other means provided that in no event will
contributions from all means exceed ten percent of the employee's annual
earnings. The purchase price of the stock is 85 percent of the lower of its
beginning-of-year or end-of-year market price. Approximately 60 percent and 55
percent of eligible employees participated in the plan in fiscal 1998 and 1997,
respectively. Under the plan, the Company sold 105,923 shares in December 1997
and 107,080 shares in December 1996.
<TABLE>
<CAPTION>
- -------------------------------------------------
1998 1997 1996
- -------------------------------------------------
<S> <C> <C> <C>
Net Income (000's)
As reported $101,795 $59,268 $52,836
Pro forma $98,592 $58,247 $52,013
Earnings per share -
Diluted
As reported $2.23 $2.13 $1.93
Pro forma $2.16 $2.10 $1.90
=================================================
</TABLE>
Accounting Treatment - The Company continues to apply APB 25 in accounting for
both plans and accordingly, no compensation has been recognized in the
consolidated financial statements. Had the Company applied the provisions of
SFAS 123 to determine the compensation cost under these plans, the Company's pro
forma net income and diluted earnings per share would have been as follows:
The fair market value of each option granted is estimated based on the
Black-Scholes model. Based on previous stock performance, volatility is
estimated to be .2720 for 1998, and .2264 for both 1997 and 1996. Dividend
yield is estimated to be
53
<PAGE> 54
3.9 percent for 1998 and 3.71 percent for both 1997 and 1996 with a risk-free
interest rate of 5.032 percent, 6.590 percent and 5.947 percent in 1998, 1997,
and 1996, respectively.
Expected life ranged from 1 to 10 years based upon experience to date and the
make-up of the optionees. Fair value of options granted under the Plan were
$8.75, $11.58, and $9.55 for 1998, 1997, and 1996 respectively.
(O) EARNINGS PER SHARE INFORMATION
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
August 31, 1998 Per Share
(In Thousands) Income Shares Amount
- -------------------------------------------------------------------------
<S> <C> <C> <C>
BASIC EPS
Income available to common stockholders 74,816 30,674 $2.44
=====
EFFECT OF DILUTIVE SECURITIES
Options 53
Convertible preferred stock 26,979 15,002
------ ------
DILUTED EPS
Income available to common stockholders
+ assumed conversions 101,795 45,729 $2.23
=========================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
August 31, 1997 Per Share
(In Thousands) Income Shares Amount
- -------------------------------------------------------------------------
<S> <C> <C> <C>
BASIC AND DILUTED EPS
Income available to common stockholders 58,983 27,644 $2.13
=========================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
August 31, 1996 Per Share
(In Thousands) Income Shares Amount
- -------------------------------------------------------------------------
<S> <C> <C> <C>
BASIC AND DILUTED EPS
Income available to common stockholders 52,408 27,136 $1.93
=========================================================================
</TABLE>
The Company adopted SFAS 128, during the second quarter of fiscal 1998. All
prior periods have been restated. SFAS 128 replaces the "primary earnings per
share" (primary EPS) and "fully diluted earnings per share" (fully diluted EPS)
with "basic earnings per share" (basic EPS) and "diluted earnings per share"
(diluted EPS). Unlike the calculation of primary EPS which includes, in its
denominator, "common stock equivalents" basic EPS is calculated using only the
actual weighted average shares outstanding during the relevant periods. The
following is a required reconciliation of the numerators and denominators of the
basic and diluted EPS computations.
The effect of dilutive options in fiscal 1997 and 1996 is insignificant.
(P) OIL AND GAS PRODUCING ACTIVITIES
The following is historical revenue and cost information relating to the
Company's production operations:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capitalized costs at end of year
Unproved properties $3,505 $2,994 $11,330
Proved properties 320,055 155,208 129,035
- -----------------------------------------------------------------------------------------------
Total capitalized costs 323,560 158,202 140,365
Accumulated depreciation, depletion, and amortization 100,601 83,457 74,129
- -----------------------------------------------------------------------------------------------
Net capitalized costs $222,959 $74,745 $66,236
===============================================================================================
Costs incurred during the year:
Property acquisition costs (unproved) $601 $174 $231
Exploitation costs $6 $71 $601
Development costs $15,315 $6,683 $2,811
Purchase of minerals in place $151,019 $21,489 $43,064
- -----------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net revenues from production:
Sales to unaffiliated customers $30,003 $24,141 $17,325
Gas sold to affiliates 12,312 14,018 7,856
- -----------------------------------------------------------------------------------------------
Net revenues from production 42,315 38,159 25,181
- -----------------------------------------------------------------------------------------------
Production costs 9,478 7,918 5,494
Exploitation expenses 351 (12) 574
Depreciation, depletion, and amortization 18,210 19,246 18,552
Income tax expense 5,522 4,258 171
- -----------------------------------------------------------------------------------------------
Total expenses 33,561 31,410 24,791
- -----------------------------------------------------------------------------------------------
Results of operations from producing activities $8,754 $6,749 $390
===============================================================================================
</TABLE>
The accompanying schedule presents the results of operation of the Company's oil
and gas producing activities. The results exclude general office overhead and
interest expense attributable to oil and gas production.
54
<PAGE> 55
(Q) OIL AND GAS RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------
OIL GAS
PROVED RESERVES (MBBLS) (MMCF)
- ---------------------------------------------------------------------
<S> <C> <C>
August 31, 1995 3,247 39,226
Revisions of prior estimates (59) (1,258)
Extensions, discoveries, and other additions 41 5,089
Purchases of minerals in place 928 42,347
Sales of minerals in place (1,712) (1,930)
Production (435) (9,406)
- ---------------------------------------------------------------------
August 31, 1996 2,010 74,068
Revisions of prior estimates 115 2,108
Extensions, discoveries, and other additions 111 3,009
Purchases of minerals in place 155 19,214
Sales of minerals in place (41) (515)
Production (336) (14,565)
- ---------------------------------------------------------------------
AUGUST 31, 1997 2,014 83,319
REVISIONS OF PRIOR ESTIMATES (223) (1,255)
EXTENSIONS, DISCOVERIES, AND OTHER ADDITIONS 167 23,251
PURCHASES OF MINERALS IN PLACE 1,645 89,724
SALES OF MINERALS IN PLACE (1) (174)
PRODUCTION (330) (16,818)
- ---------------------------------------------------------------------
AUGUST 31, 1998 3,272 178,047
=====================================================================
Proved developed reserves
August 31, 1996 1,642 60,497
August 31, 1997 1,615 62,115
AUGUST 31, 1998 2,228 134,346
- ---------------------------------------------------------------------
</TABLE>
Following are estimates of the Company's proved oil and gas reserves, net of
royalty interests and changes herein, for the 1998, 1997, and 1996 fiscal years.
The Company emphasizes that the volumes of reserves shown are estimates, which,
by their nature, are subject to later revision. The estimates are made by the
Company utilizing all available geological and reservoir data as well as
production performance data. These estimates are reviewed annually and revised,
either upward or downward, as warranted by additional performance data.
(R) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
Estimates of the standard measure of discounted future cash flows from proved
reserves of oil and natural gas shown in the accompanying table are based on
prices at the end of the year. Gas prices are escalated only for fixed and
determinable amounts under provisions of applicable regulations in some
contracts. These estimated future cash flows are reduced by estimated future
development and production costs based on year-end cost levels, assuming
continuation of existing economic conditions, and by estimated future income tax
expense. The tax expense is calculated by applying the current year-end
statutory tax rates to pretax net cash flows (net of tax depreciation,
depletion, and lease amortization allowances) applicable to oil and gas
production.
The changes in standardized measure of discounted future net cash flow relating
to proved oil and gas reserves are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future cash inflows $423,331 $218,708 $173,166
Future production and development costs 129,128 67,962 53,491
Future income tax expense 32,025 33,514 21,245
- --------------------------------------------------------------------------------------
Future net cash flows 262,178 117,232 98,430
10 percent annual discount for estimated
timing of cash flows 99,549 40,621 31,114
- --------------------------------------------------------------------------------------
Standardized measure of discounted future net cash
flows relating to oil and gas reserves $162,629 $76,611 $67,316
======================================================================================
</TABLE>
55
<PAGE> 56
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1998 1997 1996
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Beginning of year $76,611 $67,316 $47,827
Changes resulting from:
Sales of oil and gas produced, net of production (32,837) (30,241) (19,687)
Net changes in price, development, and production (6,269) 12,478 4,054
Extensions, discoveries, additions, and improved
recovery, less related costs 26,217 5,047 6,056
Purchases of minerals in place 94,031 19,747 42,999
Sales of minerals in place (142) (1,000) (20,962)
Revisions of previous quantity estimates (2,750) 3,159 (114)
Accretion of discount 9,865 8,084 3,885
Net change in income taxes 3,055 (7,372) (2,538)
Other, net (5,152) (607) 5,796
- ---------------------------------------------------------------------------------------
End of year $162,629 $76,611 $67,316
=======================================================================================
</TABLE>
56
<PAGE> 57
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL
PERSONS OF THE REGISTRANT
(A) DIRECTORS OF THE REGISTRANT
Information concerning the directors of the Company is shown in the 1999
definitive Proxy Statement which is incorporated herein by this reference.
(B) EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning the executive officers of the Company is included in
Part I of this Form 10-K.
(C) COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
Information on compliance with Section 16(a) of the Exchange Act is
included in the 1999 definitive Proxy Statement which is incorporated
herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is shown in the 1999 definitive Proxy
Statement which is incorporated herein by this reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Information concerning the ownership of certain beneficial owners is shown
in the 1999 definitive Proxy Statement which is incorporated herein by this
reference.
(B) SECURITY OWNERSHIP OF MANAGEMENT
Information on security ownership of directors and officers is shown in the
1999 definitive Proxy Statement which is incorporated herein by this
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
57
<PAGE> 58
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(A) DOCUMENTS FILED AS A PART OF THIS REPORT
(1) Exhibits
(3)(a) Certificate of Incorporation of WAI, Inc. (Now ONEOK, Inc.), filed
May 16, 1997 (Incorporated by reference from Exhibit 3.1 to
Amendment No. 3 to Registration Statement on Form S-4 filed August
6, 1997).
(3)(b) Certificate of Merger of ONEOK, Inc. (Formerly WAI, Inc.) Filed
November 26, 1997 (Incorporated by reference from Exhibit (1)(b)
to Form 10-Q dated May 31, 1998).
(3)(c) Amendment to Certificate of Incorporation of ONEOK, Inc., filed
January 16, 1998 (Incorporated by reference from Exhibit (1)(b) to
Form 10-Q dated May 31, 1998).
(3)(d) By-laws of ONEOK, Inc., as amended (Incorporated by reference from
Exhibit 3.2 to Amendment No. 3 to Registration Statement on Form
S-4 filed August 31, 1997).
(4)(a) Article "Fourth" of the Certificate of Incorporation of ONEOK,
Inc. (Preferred Stock and Common Stock), Incorporated by reference
from Exhibit 3.1 to Amendment No. 3 to Registration Statement on
Form S-4 filed August 31, 1997)
(4)(b) Certificate of Designation for Convertible Preferred stock of WAI,
Inc. (Now ONEOK, Inc.) filed November 26, 1997 (Incorporated by
reference from Exhibit 3.3 to Amendment No. 3 to Registration
Statement on Form S-4 filed August 31, 1997).
(4)(c) Certificate of Designation for Series C Participating Preferred
Stock of ONEOK, Inc., filed November 26, 1998 (Incorporated by
reference from Exhibit No. 1 to Form 8-A, filed November 26,
1997).
(4)(d) Indenture, dated November 28, 1989, between ONEOK Inc. and
Security Pacific National Bank, incorporated by reference from
Form S-3 Registration Statement No. 33-31979.
(4)(e) Indenture, dated December 1, 1990, between ONEOK Inc. and Security
Pacific National Bank, incorporated by reference from Form 10-K
dated August 31, 1991.
(4)(f) First Supplemental Indenture dated December 1, 1990, between ONEOK
Inc. and Security Pacific National Bank, incorporated by reference
from Form 10-K dated August 31, 1991.
(4)(g) Second Supplemental Indenture dated October 1, 1991, between ONEOK
Inc. and Security Pacific National Bank, incorporated by reference
from Form 10-K dated August 31, 1991.
NOTE: Certain instruments defining the rights of holders of
long-term debt are not being filed as exhibits hereto pursuant to
Item 601(b)(4)(iii) of Registration S-K. The Company agrees to
furnish copies of such agreements to the SEC upon request.
(4)(h) Rights Agreement, dated November 26, 1997, between ONEOK, Inc. and
Liberty Bank and Trust Company of Oklahoma City, N.A., as Rights
Agent (Incorporated by reference from Exhibit 2.3 to Amendment No.
3 to Registration Statement on Form S-4 filed August 31, 1997).
(4)(i) Shareholder Agreement, dated November 26, 1997, between Western
Resources, Inc. and ONEOK, Inc. (Incorporated by reference from
Exhibit 2.2 to Amendment No. 3 to Registration Statement on Form
S-4 filed August 31, 1997).
58
<PAGE> 59
(10)(a) Key Employee Stock Plan, incorporated by reference from the 1995
Definitive Proxy Statement.
(10)(b) Unfunded Excess Benefit Plan of ONEOK Inc., incorporated by
reference from the 1991 Definitive Proxy Statement.
(10)(c) Termination agreement between ONEOK Inc., and ONEOK Inc.
Executives dated January 20, 1984, incorporated by reference from
Form 10-K dated August 31, 1984.
(10)(d) Indemnification agreement between ONEOK Inc., and ONEOK Inc.
Officers and Directors, incorporated by reference from Form 10-K
dated August 31, 1984.
(10)(e) Ground Lease Between ONEOK Leasing Company and Southwestern
Associates dated May 15, 1983, incorporated by reference from Form
10-K dated August 31, 1983.
(10)(f) First Amendment to Ground Lease between ONEOK Leasing Company and
Southwestern Associates dated October 1, 1984, incorporated by
reference from Form 10-K dated August 31, 1984.
(10)(g) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15,
1983, incorporated by reference from Form 10-K dated August 31,
1983.
(10)(h) First Amendment to Sublease between RMZ Corp. and ONEOK Leasing
Company dated October 1, 1984, incorporated by reference from Form
10-K dated August 31, 1984.
(10)(i) ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas
Company dated August 31, 1984, incorporated by reference from Form
10-K dated August 31, 1985.
(10)(j) Private Placement Agreement ONEOK Inc. and Paine Webber
Incorporated, dated April 6, 1993, (Medium-Term Notes, Series A,
up to U.S. $150,000,000), incorporated by reference from Form 10-K
dated August 31, 1993.
(10)(k) Issuing and Paying Agency Agreement between Bank of America Trust
Company of New York, as Issuing and Paying Agent, and ONEOK Inc,
(Medium-Term Notes, Series A, up to U.S. $150,000,000),
incorporated by reference from Form 10-K dated August 31, 1993.
(10)(l) Amended and Restated Credit Agreement, dated August 12, 1998,
among ONEOK, Inc., the financial institutions signatories thereto
and Bank of America National Trust and Saving Association, as
Agent incorporated by reference from Form 8-k dated August 25,
1998.
(12) Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirement.
(12)(a) Computation of Ratio of Earnings to Combined Fixed Charges.
(21) Required information concerning the registrant's subsidiaries.
(23) Independent Auditors' Consent, filed herewith on page 68.
(27)(a) Financial Data Schedule for year ended August 31, 1998.
(27)(b) Financial Data Schedule for year ended August 31, 1997.
(27)(c) Financial Data Schedule for year ended August 31, 1996.
59
<PAGE> 60
<TABLE>
<CAPTION>
(2) Financial Statements Page No.
<S> <C>
(a) Independent Auditors' Report. 34
(b) Consolidated Statements of Income for the years ended
August 31, 1998, 1997, and 1996. 35
(c) Consolidated Balance Sheets at August 31, 1998 and 1997. 36 - 37
(d) Consolidated Statements of Cash Flows for the years ended
August 31, 1998, 1997, and 1996. 38
(e) Consolidated Statements of Shareholder's Equity for the years
ended August 31, 1998, 1997, and 1996. 39
(f) Notes to Consolidated Financial Statements. 40 - 56
</TABLE>
(3) Financial Statement Schedules
None.
(B) REPORTS ON FORM 8-K
July 23, 1998 - announcement of upgrade of corporate credit rating by
Standard & Poor's to A from A-.
August 25, 1998 - Short-term credit agreement between ONEOK, Inc. and Bank
of America.
OTHER MATTERS
None.
60
<PAGE> 61
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on this 22nd day of
September 1998.
ONEOK, Inc.
Registrant
By: /s/ J. D. NEAL
------------------------------------
J. D. Neal
Vice President, Chief Financial Officer, and
Treasurer (Principal Financial and
Accounting Officer)
/s/ B. D. EPPERSON
------------------------------------
B. D. Epperson
Vice President, Controller, and Chief
Accounting Officer
<PAGE> 62
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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 indicated, on this 22nd day of
September 1998.
/s/ LARRY BRUMMETT /s/ D. L. KYLE
- ------------------------------ -------------------------------
Larry Brummett D. L. Kyle
Chairman of the Board, President of ONEOK,
Chief Executive Chief Operating Officer
Officer, and Director And Director
/s/ E. G. ANDERSON /s/ B. H. MACKIE
- ------------------------------ -------------------------------
E. G. Anderson B. H. Mackie
Director Director
/s/ W. M. BELL /s/ J. D. NEAL
- ------------------------------ -------------------------------
W. M. Bell J. D. Neal
Director Vice President, Treasurer,
and Chief Financial Officer
/s/ D. R. CUMMINGS /s/ D. A. NEWSOM
- ------------------------------ -------------------------------
D. R. Cummings D. A. Newsom
Director Director
/s/ W. L. FORD /s/ G. D. PARKER
- ------------------------------ -------------------------------
W. L. Ford G. D. Parker
Director Director
/s/ J. M. GRAVES /s/ J. D. SCOTT
- ------------------------------ -------------------------------
J. M. Graves J. D. Scott
Director Director
/s/ S. J. JATRAS /s/ S. L. YOUNG
- ------------------------------ -------------------------------
S. J. Jatras S. L. Young
Director Director
/s/ H. R. FRICKE /s/ S. L. KITCHEN
- ------------------------------- -------------------------------
H. R. Fricke S. L. Kitchen
Director Director
<PAGE> 63
Index to Exhibits
<TABLE>
<CAPTION>
Exhibit No. Description
- ----------- -----------
<S> <C>
(3)(a) Certificate of Incorporation of WAI, Inc. (Now ONEOK, Inc.), filed
May 16, 1997 (Incorporated by reference from Exhibit 3.1 to
Amendment No. 3 to Registration Statement on Form S-4 filed August
6, 1997).
(3)(b) Certificate of Merger of ONEOK, Inc. (Formerly WAI, Inc.) Filed
November 26, 1997 (Incorporated by reference from Exhibit (1)(b)
to Form 10-Q dated May 31, 1998).
(3)(c) Amendment to Certificate of Incorporation of ONEOK, Inc., filed
January 16, 1998 (Incorporated by reference from Exhibit (1)(b) to
Form 10-Q dated May 31, 1998).
(3)(d) By-laws of ONEOK, Inc., as amended (Incorporated by reference from
Exhibit 3.2 to Amendment No. 3 to Registration Statement on Form
S-4 filed August 31, 1997).
(4)(a) Article "Fourth" of the Certificate of Incorporation of ONEOK,
Inc. (Preferred Stock and Common Stock), Incorporated by reference
from Exhibit 3.1 to Amendment No. 3 to Registration Statement on
Form S-4 filed August 31, 1997)
(4)(b) Certificate of Designation for Convertible Preferred stock of WAI,
Inc. (Now ONEOK, Inc.) filed November 26, 1997 (Incorporated by
reference from Exhibit 3.3 to Amendment No. 3 to Registration
Statement on Form S-4 filed August 31, 1997).
(4)(c) Certificate of Designation for Series C Participating Preferred
Stock of ONEOK, Inc., filed November 26, 1998 (Incorporated by
reference from Exhibit No. 1 to Form 8-A, filed November 26,
1997).
(4)(d) Indenture, dated November 28, 1989, between ONEOK Inc. and
Security Pacific National Bank, incorporated by reference from
Form S-3 Registration Statement No. 33-31979.
(4)(e) Indenture, dated December 1, 1990, between ONEOK Inc. and Security
Pacific National Bank, incorporated by reference from Form 10-K
dated August 31, 1991.
(4)(f) First Supplemental Indenture dated December 1, 1990, between ONEOK
Inc. and Security Pacific National Bank, incorporated by reference
from Form 10-K dated August 31, 1991.
(4)(g) Second Supplemental Indenture dated October 1, 1991, between ONEOK
Inc. and Security Pacific National Bank, incorporated by reference
from Form 10-K dated August 31, 1991.
NOTE: Certain instruments defining the rights of holders of
long-term debt are not being filed as exhibits hereto pursuant to
Item 601(b)(4)(iii) of Registration S-K. The Company agrees to
furnish copies of such agreements to the SEC upon request.
(4)(h) Rights Agreement, dated November 26, 1997, between ONEOK, Inc. and
Liberty Bank and Trust Company of Oklahoma City, N.A., as Rights
Agent (Incorporated by reference from Exhibit 2.3 to Amendment No.
3 to Registration Statement on Form S-4 filed August 31, 1997).
(4)(i) Shareholder Agreement, dated November 26, 1997, between Western
Resources, Inc. and ONEOK, Inc. (Incorporated by reference from
Exhibit 2.2 to Amendment No. 3 to Registration Statement on Form
S-4 filed August 31, 1997).
</TABLE>
<PAGE> 64
<TABLE>
<S> <C>
(10)(a) Key Employee Stock Plan, incorporated by reference from the 1995
Definitive Proxy Statement.
(10)(b) Unfunded Excess Benefit Plan of ONEOK Inc., incorporated by
reference from the 1991 Definitive Proxy Statement.
(10)(c) Termination agreement between ONEOK Inc., and ONEOK Inc.
Executives dated January 20, 1984, incorporated by reference from
Form 10-K dated August 31, 1984.
(10)(d) Indemnification agreement between ONEOK Inc., and ONEOK Inc.
Officers and Directors, incorporated by reference from Form 10-K
dated August 31, 1984.
(10)(e) Ground Lease Between ONEOK Leasing Company and Southwestern
Associates dated May 15, 1983, incorporated by reference from Form
10-K dated August 31, 1983.
(10)(f) First Amendment to Ground Lease between ONEOK Leasing Company and
Southwestern Associates dated October 1, 1984, incorporated by
reference from Form 10-K dated August 31, 1984.
(10)(g) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15,
1983, incorporated by reference from Form 10-K dated August 31,
1983.
(10)(h) First Amendment to Sublease between RMZ Corp. and ONEOK Leasing
Company dated October 1, 1984, incorporated by reference from Form
10-K dated August 31, 1984.
(10)(i) ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas
Company dated August 31, 1984, incorporated by reference from Form
10-K dated August 31, 1985.
(10)(j) Private Placement Agreement ONEOK Inc. and Paine Webber
Incorporated, dated April 6, 1993, (Medium-Term Notes, Series A,
up to U.S. $150,000,000), incorporated by reference from Form 10-K
dated August 31, 1993.
(10)(k) Issuing and Paying Agency Agreement between Bank of America Trust
Company of New York, as Issuing and Paying Agent, and ONEOK Inc,
(Medium-Term Notes, Series A, up to U.S. $150,000,000),
incorporated by reference from Form 10-K dated August 31, 1993.
(10)(l) Amended and Restated Credit Agreement, dated August 12, 1998,
among ONEOK, Inc., the financial institutions signatories thereto
and Bank of America National Trust and Saving Association, as
Agent incorporated by reference from Form 8-k dated August 25,
1998.
(12) Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirement.
(12)(a) Computation of Ratio of Earnings to Fixed Charges.
(21) Required information concerning the registrant's subsidiaries.
(23) Independent Auditors' Consent, filed herewith on page 68.
(27)(a) Financial Data Schedule for year ended August 31, 1998.
(27)(b) Financial Data Schedule for year ended August 31, 1997.
(27)(c) Financial Data Schedule for year ended August 31, 1996.
</TABLE>
<PAGE> 1
EXHIBIT (12)
ONEOK, Inc.
Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirements
August 31, 1998
<TABLE>
<CAPTION>
YEARS ENDED AUGUST 31,
----------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
FIXED CHARGES, AS DEFINED
INTEREST ON LONG-TERM DEBT 30,846 31,354 31,748 32,345 32,979
OTHER INTEREST 3,723 3,376 3,184 4,934 1,855
AMORTIZATION OF DEBT ISSUE COSTS 506 518 530 512 525
INTEREST ON LEASE AGREEMENTS 2,325 2,266 2,266 2,266 2,266
----------------------------------------------------
TOTAL FIXED CHARGES 37,400 37,514 37,728 40,057 37,625
PREFERRED DIVIDEND REQUIREMENTS 26,979 285 428 428 428
----------------------------------------------------
TOTAL FIXED CHARGES
AND PREFERRED DIVIDEND
REQUIREMENTS 64,379 37,799 38,156 40,485 38,053
====================================================
EARNINGS BEFORE INCOME TAXES 168,380 94,107 85,873 68,146 57,276
TOTAL FIXED CHARGES 37,400 37,514 37,728 40,057 37,625
----------------------------------------------------
EARNINGS AVAILABLE FOR
COMBINED FIXED CHARGES
AND PREFERRED DIVIDEND
REQUIREMENTS 205,780 131,621 123,601 108,203 94,901
====================================================
RATIO OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED
DIVIDEND REQUIREMENTS 3.20x 3.48x 3.24x 2.67x 2.49x
====================================================
</TABLE>
FOR PURPOSES OF COMPUTING THE RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED DIVIDEND REQUIREMENTS, "EARNINGS" CONSISTS OF NET INCOME PLUS FIXED
CHARGES AND INCOME TAXES. "FIXED CHARGES CONSISTS OF INTEREST CHARGES, THE
AMORTIZATION OF DEBT ISSUE COSTS AND THE REPRESENTATIVE INTEREST PORTION OF
OPERATING LEASES. "PREFERRED DIVIDEND REQUIREMENTS" CONSISTS OF THE PRE-TAX
PREFERRED DIVIDEND REQUIREMENT.
<PAGE> 1
EXHIBIT (12)(a)
ONEOK, Inc.
Computation of Ratio of Earnings to Fixed Charges
August 31, 1998
<TABLE>
<CAPTION>
YEARS ENDED AUGUST 31,
----------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
FIXED CHARGES, AS DEFINED
INTEREST ON LONG-TERM DEBT 30,846 31,354 31,748 32,345 32,979
OTHER INTEREST 3,723 3,376 3,184 4,934 1,855
AMORTIZATION OF DEBT ISSUE COSTS 506 518 530 512 525
INTEREST ON LEASE AGREEMENTS 2,325 2,266 2,266 2,266 2,266
----------------------------------------------------
TOTAL FIXED CHARGES 37,400 37,514 37,728 40,057 37,625
====================================================
EARNINGS BEFORE INCOME TAXES 168,380 94,107 85,873 68,146 57,276
----------------------------------------------------
EARNINGS AVAILABLE FOR
FIXED CHARGES 205,780 131,621 123,601 108,203 94,901
====================================================
RATIO OF EARNINGS TO
FIXED CHARGES 5.50x 3.51x 3.28x 2.70x 2.52x
====================================================
</TABLE>
FOR PURPOSES OF COMPUTING THE RATIO OF EARNINGS TO FIXED CHARGES, "EARNINGS"
CONSISTS OF NET INCOME PLUS FIXED CHARGES AND INCOME TAXES. "FIXED CHARGES
CONSISTS OF INTEREST CHARGES, THE AMORTIZATION OF DEBT ISSUE COSTS AND THE
REPRESENTATIVE INTEREST PORTION OF OPERATING LEASES.
<PAGE> 1
EXHIBIT (21)
Following are ONEOK, Inc.'s wholly-owned subsidiaries and corporate
divisions:
<TABLE>
<CAPTION>
Year of
State of Establishment or
Incorporation Incorporation
<S> <C> <C>
ONEOK, Inc. Oklahoma May 16, 1997
Kansas Gas Marketing Company Kansas December 2, 1997
Kansas Gas Service Company Kansas June 30, 1997
ONG Transmission Company Delaware April 4, 1968
ONG Transmission Assets, L.L.C. Oklahoma August 28, 1998
ONG Sayre Storage Company Delaware March 9, 1964
ONEOK Technology Company Delaware August 31, 1992
Oklahoma Natural Energy Service Company Oklahoma February 18, 1998
OkTex Pipeline Company Delaware September 19, 1990
ONEOK Resources Company Delaware October 5, 1970
ONEOK Service Company Oklahoma June 19, 1998
ONEOK Gas Processing, L.L.C. Oklahoma August 24, 1998
ONEOK Gas Transportation, L.L.C. Oklahoma August 25, 1998
ONROK International, Inc. Delaware February 6, 1997
ONEOK Producer Services, L.L.C. Oklahoma August 25, 1998
ONEOK Gas Marketing Company Delaware September 10, 1992
Mid Continent Market Center Gathering, Inc. (A subsidiary of
Mid Continent Market Center, Inc.) Kansas December 13, 1994
Mid Continent Market Center, Inc. Kansas December 13, 1994
ONEOK Power Marketing Company Delaware September 6, 1996
Fifth Street Investment Corporation Oklahoma June 5, 1995
ONEOK Leasing Company Delaware March 18, 1983
ONEOK Parking Company Delaware March 18, 1983
ONEOK Financing Company Kansas August 31, 1998
</TABLE>
<PAGE> 1
EXHIBIT 23
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
ONEOK, Inc.:
We consent to incorporation by reference in the Registration Statements Nos.
333-41263, 333-41265, 333-41267, and 333-41269 on Form S-8 and nos 333-44915,
333-57433, and 333-62279 on Form S-3 of ONEOK, Inc. of our report dated
September 18, 1998, relating to the consolidated balance sheets of ONEOK, Inc.
and subsidiaries as of August 31, 1998 and 1997, and the related consolidated
statements of income, shareholders' equity, and cash flows for each of the
years in the three-year period ended August 31, 1998, which report appears in
the August 31, 1998, annual report on Form 10-K of ONEOK, Inc.
KPMG Peat Marwick LLP
Tulsa, Oklahoma
September 18, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENT OF EARNINGS FOR THE 1998 FISCAL YEAR ENDED AUGUST 31,
1998 AND THE CONSOLIDATED BALANCE SHEET AT AUGUST 31, 1998, FOR ONEOK, INC. AND
SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1998
<PERIOD-START> SEP-01-1997
<PERIOD-END> AUG-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,373,720
<OTHER-PROPERTY-AND-INVEST> 314,245
<TOTAL-CURRENT-ASSETS> 338,073
<TOTAL-DEFERRED-CHARGES> 395,449
<OTHER-ASSETS> 1,000
<TOTAL-ASSETS> 2,422,487
<COMMON> 329,741
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 270,808
<TOTAL-COMMON-STOCKHOLDERS-EQ> 600,549
0
568,322
<LONG-TERM-DEBT-NET> 312,355
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 212,000
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0
<CAPITAL-LEASE-OBLIGATIONS> 1,772
<LEASES-CURRENT> 1,265
<OTHER-ITEMS-CAPITAL-AND-LIAB> 108,766
<TOT-CAPITALIZATION-AND-LIAB> 2,422,487
<GROSS-OPERATING-REVENUE> 1,835,402
<INCOME-TAX-EXPENSE> 66,585
<OTHER-OPERATING-EXPENSES> 1,631,947
<TOTAL-OPERATING-EXPENSES> 1,698,532
<OPERATING-INCOME-LOSS> 136,870
<OTHER-INCOME-NET> 0
<INCOME-BEFORE-INTEREST-EXPEN> 136,870
<TOTAL-INTEREST-EXPENSE> 35,075
<NET-INCOME> 101,795
26,979
<EARNINGS-AVAILABLE-FOR-COMM> 74,816
<COMMON-STOCK-DIVIDENDS> 36,831
<TOTAL-INTEREST-ON-BONDS> 0
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<EPS-PRIMARY> 2.44
<EPS-DILUTED> 2.23
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENT OF EARNINGS FOR THE 1997 FISCAL YEAR ENDED AUGUST 31,
1997 AND THE CONSOLIDATED BALANCE SHEET AT AUGUST 31, 1997, FOR ONEOK, INC. AND
SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1997
<PERIOD-START> SEP-01-1996
<PERIOD-END> AUG-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 718,265
<OTHER-PROPERTY-AND-INVEST> 125,396
<TOTAL-CURRENT-ASSETS> 207,277
<TOTAL-DEFERRED-CHARGES> 186,469
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,237,407
<COMMON> 229,803
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 232,823
<TOTAL-COMMON-STOCKHOLDERS-EQ> 462,626
0
0
<LONG-TERM-DEBT-NET> 328,214
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 45,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 18,909
0
<CAPITAL-LEASE-OBLIGATIONS> 1,728
<LEASES-CURRENT> 1,434
<OTHER-ITEMS-CAPITAL-AND-LIAB> 379,496
<TOT-CAPITALIZATION-AND-LIAB> 1,237,407
<GROSS-OPERATING-REVENUE> 1,161,927
<INCOME-TAX-EXPENSE> 34,839
<OTHER-OPERATING-EXPENSES> 1,033,812
<TOTAL-OPERATING-EXPENSES> 1,068,651
<OPERATING-INCOME-LOSS> 93,276
<OTHER-INCOME-NET> 0
<INCOME-BEFORE-INTEREST-EXPEN> 93,276
<TOTAL-INTEREST-EXPENSE> 34,008
<NET-INCOME> 59,268
285
<EARNINGS-AVAILABLE-FOR-COMM> 58,983
<COMMON-STOCK-DIVIDENDS> 33,195
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 152,051
<EPS-PRIMARY> 2.13
<EPS-DILUTED> 2.13
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENT OF EARNINGS FOR THE 1997 FISCAL YEAR ENDED AUGUST 31,
1996 AND THE CONSOLIDATED BALANCE SHEET AT AUGUST 31, 1996 FOR ONEOK, INC. AND
SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1996
<PERIOD-START> SEP-01-1995
<PERIOD-END> AUG-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 691,291
<OTHER-PROPERTY-AND-INVEST> 106,022
<TOTAL-CURRENT-ASSETS> 233,146
<TOTAL-DEFERRED-CHARGES> 189,432
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,219,891
<COMMON> 207,084
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 207,611
<TOTAL-COMMON-STOCKHOLDERS-EQ> 414,695
0
9,000
<LONG-TERM-DEBT-NET> 336,821
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 50,223
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 15,050
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 394,102
<TOT-CAPITALIZATION-AND-LIAB> 1,219,891
<GROSS-OPERATING-REVENUE> 1,224,345
<INCOME-TAX-EXPENSE> 33,037
<OTHER-OPERATING-EXPENSES> 1,103,695
<TOTAL-OPERATING-EXPENSES> 1,136,732
<OPERATING-INCOME-LOSS> 87,613
<OTHER-INCOME-NET> 0
<INCOME-BEFORE-INTEREST-EXPEN> 87,613
<TOTAL-INTEREST-EXPENSE> 34,777
<NET-INCOME> 52,836
428
<EARNINGS-AVAILABLE-FOR-COMM> 52,408
<COMMON-STOCK-DIVIDENDS> 32,022
<TOTAL-INTEREST-ON-BONDS> 0
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<EPS-PRIMARY> 1.93
<EPS-DILUTED> 1.93
</TABLE>
