100 West Fifth Street
Tulsa, OK 74103
ONEOK, INC.
2000
ANNUAL REPORT TO THE
SECURITIES AND EXCHANGE COMMISSION
FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the fiscal year ended DECEMBER 31, 2000.
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.
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(Exact name of registrant as specified in its charter)
Oklahoma 73-1520922
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation of organization)
100 WEST FIFTH STREET, TULSA, OK 74103
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(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code (918) 588-7000
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(Former name if changes since last report.)
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Securities registered pursuant to Section 12(b) of the Act:
Common stock, with par value of $0.01 New York Stock Exchange
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(Title of Each Class) (Name of Each Exchange on
which Registered)
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of 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.__
Aggregate market value of registrant's voting stock held by nonaffiliates based
on the closing trade price on March 14, 2001, was: Common stock of $ 1,214.2
million
On March 14, 2001, the Company had 29,651,273 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Documents Part of Form 10-K
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Portions of the definitive proxy statement dated Part III
April 11 ,2001, to be delivered to shareholders
in connection with the Annual Meeting of
Shareholders to be held May 17, 2001.
ONEOK, INC.
2000 ANNUAL REPORT ON FORM 10-K
Part I. Page No.
Item 1. Business 3-16
Item 2. Properties 16-22
Item 3. Legal Proceedings 23-26
Item 4. Results of Votes of Security Holders 27
PART II.
Item 5. Market Price and Dividends on the Registrant's
Common Stock and Related Shareholder Matters 28
Item 6. Selected Financial Data 29
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 30-52
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 53
Item 8. Financial Statements and Supplementary Data 54-87
Item 9. Changes in and Disagreements with Accountants
On Accounting and Financial Disclosures 87
PART III.
Item 10. Directors, Executive Officers, Promoters, and
Control Persons of the Registrant 88
Item 11. Executive Compensation 88
Item 12. Security Ownership of Certain Beneficial Owners
and Management 88
Item 13. Certain Relationships and Related Transactions 88
PART IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 89-92
2
PART I.
ITEM 1. BUSINESS
GENERAL - ONEOK, Inc., an Oklahoma corporation, was organized on May 16, 1997.
On November 26, 1997, it acquired the gas business of Western Resources, Inc.
(Western) 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" or "ONEOK") engage in
several aspects of the energy business. The Company purchases, gathers,
processes, transports, stores, and distributes natural gas. The Company drills
for and produces oil and natural gas, extracts, sells and markets natural gas
liquids, and is engaged in the gas marketing and trading business. The Company
also engages in wholesale marketing of electricity on a limited basis. In
addition, the Company leases and operates their headquarters office building
located in downtown Tulsa, Oklahoma (leasing excess space to others) and owns
and operates a related parking facility.
CHANGE IN FISCAL YEAR - In October 1999, the Company changed its fiscal year end
from August 31 to December 31. Accordingly, the Company filed a Transition
Report on Form 10-Q for the four months ended December 31, 1999, the Company's
Transition Period preceding the beginning of the new fiscal year.
DEFINITIONS
Following are definitions of abbreviations used in this Form 10-K:
Bbl 42 United States (U.S.) gallons, the basic unit for measuring crude oil
and natural gas condensate.
MBbls One thousand barrels.
MBbls/d One thousand barrels per day.
MMBbls One million barrels.
Btu British Thermal Unit - a measure of the amount of heat required to
raise the temperature of one pound of water one degree Fahrenheit.
Mcf One thousand cubic feet of gas.
MMcf One million cubic feet of gas.
MMcf/d One million cubic feet of gas per day.
Bcf One billion cubic feet of gas.
Bcf/d One billion cubic feet of gas per day.
Bcfe Bcf equivalent, whereby barrels of oil are converted to Bcf using six
Bcfs of natural gas to one barrel of oil.
NGLs Natural gas liquids
ACQUISITIONS AND SALES
The Company's strategy is to acquire assets that enhance the earnings potential
of the Company and utilize existing assets to maximize earnings. The Company
expects to continue evaluating and assessing acquisition opportunities to
further complement its existing asset base. The Company also from time to time
sells assets when deemed less strategic or as other conditions warrant.
3
KINDER MORGAN, INC. - On April 5, 2000, the Company acquired certain natural gas
gathering and processing assets located in Oklahoma, Kansas and West Texas from
Kinder Morgan, Inc. (KMI). The Company also acquired KMI's marketing and trading
operations, as well as some storage and transmission pipelines in the Mid
Continent region. The Company paid approximately $109 million for these assets
plus working capital of approximately $53 million, which was subject to
adjustment. The working capital adjustment was made in the first quarter 2001,
resulting in the Company receiving approximately $4 million. The Company also
assumed certain liabilities including those related to an operating lease for a
processing plant for which the Company established a liability for uneconomic
lease obligation and some firm capacity lease obligations to third parties for
which the Company established a reserve for out-of-market terms of those
obligations. This acquisition includes more than 12,000 miles of gathering and
transportation pipeline, natural gas processing plants with capacity of 1.26
Bcf/d and storage facilities with a combined capacity of approximately 10 Bcf.
The current throughput of these gathering and processing assets is approximately
760 MMcf/d. Approximately 350 employees were added to the Company's workforce as
part of the acquisition.
DYNEGY, INC. - In March 2000, the Company acquired natural gas processing plants
with an approximate capacity of 375 MMcf/d and approximately 7,000 miles of gas
gathering and transmission pipeline systems in Oklahoma, Kansas and Texas from
Dynegy, Inc. (Dynegy). The Company paid approximately $305 million for these
assets, which included a $3 million preliminary adjustment for working capital.
The working capital adjustment is expected to be finalized during the first
quarter of fiscal 2001. The current throughput of the assets is approximately
240 MMcf/d. Production of NGLs from the assets averages 25MBbls/d. Approximately
75 employees have been added to the ONEOK workforce as part of the acquisition.
The majority of these employees are in field operations in Western Oklahoma, the
Texas panhandle and Southern Kansas.
INDIAN BASIN GAS PROCESSING PLANT - During the first quarter of 2000, the
Company sold its 42.4 percent interest in the Indian Basin Gas Processing Plant
and gathering system for $55 million to El Paso Field Services Company, a
business unit of El Paso Energy Corporation.
BUSINESS SEGMENTS
The Company reports operations in the following reportable segments:
o Marketing and Trading
o Gathering and Processing
o Transportation and Storage
o Distribution
o Production
o Other
Beginning in January 2001, the Company will add a new segment, "Power" which
will include the operations of the 300-megawatt gas-fired merchant power plant
the Company is in the process of constructing. The Company expects this plant,
configured to supply electric power during peak periods, to be completed and
operational in June 2001. The Company has a signed definitive agreement with a
third party for a 15-year term providing for the right to purchase approximately
25 percent of the plant's generating capacity.
MARKETING AND TRADING - The Marketing and Trading segment, previously referred
to as the Marketing segment, conducts its business through ONEOK Energy
Marketing and Trading Company (OEMT). The Company changed the name of ONEOK Gas
Marketing Company to OEMT during 2000. OEMT is actively engaged in value
creation through marketing and trading of natural gas to both wholesale and
retail customers in 28 states using leased gas storage from related parties and
others. The Company has executed an integrated wholesale energy business
strategy based on expanding their existing marketing, trading and arbitrage
opportunities in the natural gas and power markets. The combination of owning or
controlling strategic assets and a trusted, reliable marketing franchise is
expected to allow the Company to continue to capitalize on existing marketing,
trading and arbitrage opportunities.
4
The Company primarily conducts its operations in the Mid Continent region of the
US. However, with the acquisition of KMI's marketing and trading operations, the
Marketing and Trading segment expanded its presence to the west coast, Texas,
throughout the Rockies, and to the Chicago city gate areas. It also conducts
wholesale trading of electricity on a limited basis through ONEOK Power
Marketing Company.
During 2000, the Oklahoma Corporation Commission (OCC), required Oklahoma
Natural Gas Company (ONG), an affiliated company, to unbundle its transportation
services and open its supply. OEMT was the successful bidder to supply gas to
ONG for its gas sales requirements for the next five years beginning in November
2000. In response, the Company entered into firm supply arrangements with major
producers and large independents that average in length from two to five years.
GATHERING AND PROCESSING - The Gathering and Processing segment gathers and
processes natural gas and fractionates, stores and markets NGLs primarily
through its subsidiaries ONEOK Field Services Company and ONEOK NGL Marketing
Company. These activities are conducted primarily in Oklahoma, Kansas and Texas.
In early 2000, the Company acquired certain gathering and processing assets from
KMI and Dynegy. These asset acquisitions included natural gas processing plants
with a combined capacity of approximately 1.6 Bcf/d and approximately 13,400
miles of gathering lines. As a result of these acquisitions, the Company
expanded to include the production of helium and created a new business, ONEOK
NGL Marketing Company.
The Company also engaged in a strategic process of assessing and renegotiating
its "Keep Whole" contract mix to mitigate the commodity price risk associated
with these contracts. The recent asset acquisitions have allowed the Company to
engage in asset consolidation and rationalization to better utilize the
Company's assets and develop strategic assets that complement the Company's core
assets.
TRANSPORTATION AND STORAGE - The Transportation and Storage segment provides
natural gas transportation and storage services. These operations are primarily
conducted through ONEOK Gas Transportation, L.L.C. (OGT), ONEOK Sayre Storage
Company (Sayre), ONEOK WesTex Transmission, Inc. (WesTex), ONEOK Texas Gas
Storage L. P. (OTGS), Market Center Gathering, Inc., Mid Continent Market
Center, Inc. (MCMC), Mid Continent Transportation, Inc. (MCTI), ONEOK Producer
Services, Inc., and ONEOK Gas Storage, L.L.C. (OGS). The acquisition of the KMI
assets expanded the Company's transmission and storage operations into Texas
where the Company now owns and operates through its wholly owned subsidiary,
OTGS, three storage facilities with approximately 10 Bcf capacity, and WesTex
which operates approximately 4,733 miles of intrastate pipeline in Texas. Both
OGTS and WesTex are regulated by the Texas Railroad Commission (TRC). In July
1999, the storage assets located in Oklahoma were removed from regulation by the
OCC. Following that, OGS and Sayre were granted market based rate authority by
the Federal Energy Regulatory Commission (FERC). In a May 2000 OCC Order,
certain transportation assets in Oklahoma included in the Transportation and
Storage segment became a separate regulated utility from the Distribution
segment. MCMC and MCTI's operations continue to be regulated by the KCC.
DISTRIBUTION - The Distribution segment provides natural gas distribution in
Oklahoma and Kansas. The Company's distribution operations in Oklahoma are
conducted through ONG and KGS, both divisions of ONEOK, Inc., which serve
residential, commercial, and industrial customers. ONG is regulated by the OCC
and KGS is regulated by the KCC. The Distribution segment serves approximately
80 percent of Oklahoma's gas retail markets and 67 percent of Kansas' gas retail
markets.
PRODUCTION - The Production segment produces natural gas and oil primarily in
Oklahoma, Kansas and Texas through ONEOK Resources Company. The Production
segment's strategy is to acquire and develop properties. During 2000, the
Company participated in drilling 93 wells of which 81 were gas, four were oil
and eight were dry holes.
OTHER - The primary companies in the Other segment include ONEOK Leasing
Company and ONEOK Parking Company. ONEOK Leasing Company leases and operates a
headquarters office building. ONEOK Parking Company owns and operates a parking
garage adjacent to the Company's corporate headquarters.
5
ENVIRONMENTAL MATTERS - The Company has 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 December 31, 2000, the costs of the
investigations and risk analysis have been immaterial. Limited information is
available about the sites and no testing has been performed. Management's best
estimate of the cost of remediation ranges from $100,000 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 and the Company anticipates it will be
allowed to recover such costs. 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, any material costs could
adversely affect 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 2000 totaled $472,000.
There have been no material effects upon earnings or the Company's competitive
position during 2000 related to compliance with environmental regulations.
EMPLOYEES - The Company employed 3,664 persons at December 31, 2000. KGS employs
870 people who are subject to collective bargaining contracts. The Company did
not experience any strikes or work stoppages during 2000. The Company's current
contracts with the Unions are as follows:
UNION EMPLOYEES CONTRACT EXPIRES
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United Steelworkers of America 489 June 6, 2002
International Union of Operating Engineers 17 June 6, 2002
Gas Workers Metal Trades of the United Association of Journeymen and
Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada 11 June 6, 2002
International Brotherhood of Electrical Workers 353 July 1, 2003
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SEGMENT FINANCIAL INFORMATION - For financial and statistical information
regarding the Company's business units by segment, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and Note L of
Notes to Consolidated Financial Statements.
DESCRIPTION OF BUSINESS SEGMENTS
(A) MARKETING AND TRADING
GENERAL - The Company is engaged in the marketing and trading of natural gas to
retail and wholesale customers in 28 states throughout the United States. Due to
expanded supply, storage capabilities, and recent acquisitions, the Company
markets gas from the West Coast to the Chicago city gate. The marketing
operation has evolved from an intrastate aggregator into an interstate
aggregator. Of the Company's consolidated revenues, revenues from the Marketing
and Trading segment represent approximately 65.7, 42.0 and 41.0 percent for
fiscal years 2000, 1999, and 1998, respectively. Operating income from the
Marketing and Trading segment is 15.4, 12.0, and 6.5 percent of the consolidated
operating income for fiscal years 2000, 1999, and 1998, respectively.
6
The Company engages in price risk management activities for both trading and
non-trading purposes. On January 1, 2000, the Company adopted Emerging Issues
Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities" (EITF 98-10) for its energy trading contracts. EITF 98-10 requires
entities involved in energy trading activities to account for energy trading
contracts using mark-to-market accounting. Forwards, swaps, options, and energy
transportation and storage contracts utilized for trading activities are
reflected at fair value as assets and liabilities from price risk management
activities in the consolidated balance sheets. The fair value of these assets
and liabilities are affected by the actual timing of settlements related to
these contracts and current period changes resulting primarily from newly
originated transactions and the impact of price movements. Changes in fair value
are recognized in net revenues, on a net basis, in the consolidated statement of
income. Market prices used to fair value these assets and liabilities reflect
management's best estimate considering various factors including closing
exchange and over-the-counter quotations, time value and volatility underlying
the commitments. Market prices are adjusted for the potential impact of
liquidating the Company's position in an orderly manner over a reasonable period
of time under present market conditions.
The Company is in the process of developing its "Oneokenergy.com" portal
website. This website will initially provide valuable energy news, commodity and
weather information to OEMT's customer base. This phase of the website is
expected to be online in March 2001. Future plans include the ability to do all
of OEMT's administration online, from contract administration to invoicing.
Longer-term plans include the development of a non-business hours and holiday
trading system that customers can use.
MARKET CONDITIONS AND BUSINESS SEASONALITY - In response to a very competitive
marketing and trading environment resulting from continued deregulation of the
retail natural gas markets and the restructuring of the U.S. retail and
wholesale electricity markets, the Company's strategy is to concentrate its
efforts on capitalizing on short-term pricing volatility through marketing,
trading and arbitrage opportunities provided by strategic control or ownership
of storage, generation and transportation assets. OEMT focuses on building and
strengthening supplier and customer relationships to execute their strategy.
Management believes that its location in the heart of the natural gas producing
area of the United States as well as the benefits derived from vertically
integrating the gas marketing operations with the Company's other business, will
provide strategic advantages necessary to compete successfully in the
competitive natural gas market.
The marketing and trading operations acquired from KMI included a significant
amount of baseload contracts which typically have a lower margin than OEMT's
historical margin. The Company is assessing the strategic fit of these baseload
contracts.
The Marketing and Trading segment's revenue and gross margin on gas sales are
subject to fluctuations during the year primarily due to the impact certain
seasonal factors have on sales volumes and the price of natural gas and
electricity. Natural gas sales volumes are typically higher in the winter
heating months than in the summer months, reflecting increased demand due to
greater heating requirements and, typically, higher natural gas prices. However,
with the increased development of gas-fired electric generating plants
throughout the United States, historical seasonality associated with natural gas
sales volumes and prices may become less pronounced in the future.
PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising from
fluctuations in both the market price and transportation costs of natural gas,
OEMT manages its portfolio of contracts and its assets in order to maximize
value, minimize the associated risks and provide overall liquidity. In doing so,
OEMT uses price risk management instruments, including swaps, options, futures
and physical commodity-based contracts to manage exposures to market price
movements. See Item 7A. Quantitative and Qualitative Disclosures About Market
Risk and Note C to the Notes to Consolidated Financial Statements.
7
(B) GATHERING AND PROCESSING
GENERAL - The Company's Gathering and Processing segment is engaged in the
gathering and processing of natural gas and the fractionation, storage and
marketing of NGLs. The Company owns and operates 24 gas processing plants, five
of which are currently idle, leases and operates one gas processing plant, has
an ownership interest in four gas processing plants that are operated by other
owners and owns approximately 19,300 miles of natural gas gathering systems. The
Company's total capacity of the plants the Company owns, leases or has an
ownership interest in is 2.2 Bcf/d. The Company has experienced significant
growth in this segment, beginning with the acquisition of the Koch assets in
1999 and the KMI and Dynegy assets in early 2000.
The gas processing operation includes the extraction of NGLs and the separation
(fractionation) of mixed NGLs into component products (ethane, propane, iso
butane, normal butane and natural gasoline). The Company has the ability to
extract helium at two of its plants located in Kansas. The NGL component
products are used by and sold to a diverse customer base of end users for
petrochemical feedstock, residential heating and cooking, and blending into
motor fuels. The gathering operation, which connects third party and affiliates
producing wells to the processing plants, consists of the gathering of natural
gas through pipeline systems and compression and dehydration services.
The Company generally processes gas under three types of contracts. Under the
Company's "Percent of Proceeds" -(POP) contracts the producer is paid a
percentage of the market value of the natural gas and NGLs that are processed.
The Company's "Keep Whole" contracts allow the Company to replace the BTUs
extracted as NGLs with gas, which keeps the producer whole on Btu's and allows
the Company to retain and sell the NGLs. With the acquisition of KMI and Dynegy
assets, the Company now processes some gas for a "Fee." Under the "Fee"
contracts, the Company is paid a fee for NGL extraction.
During 2000, the Company processed an average of 1.1 Bcf/d of natural gas and
produced an average of 69 MBbls/d of NGLs. The Company markets its own NGL
production through ONEOK NGL Marketing Company and purchases NGLs from third
parties for resale. During 2000, the Company sold approximately 68.7 MBbls/d of
NGLs to a diverse base of over 200 customers.
The Company's operating results were significantly impacted by the KMI and
Dynegy acquisitions as well as the increase in natural gas, oil and NGL prices.
Of the Company's consolidated revenues, revenues from the Gathering and
Processing segment represent approximately 12.6, 3.9 and 3.5 percent for fiscal
years 2000, 1999, and 1998, respectively. Operating income from the Gathering
and Processing segment is 33.2, 7.7, and 8.2 percent of the consolidated
operating income for fiscal years 2000, 1999, and 1998, respectively.
MARKET CONDITIONS AND BUSINESS SEASONALITY - Changes in the midstream NGLs
industry and volatility in NGL prices in the late 1990's and continuing into
2000, has placed significant pressure on operating margins in the industry.
Despite significant consolidation in the recent past, the U.S. midstream
industry remains relatively fragmented and the Company faces competition from a
variety of companies including major integrated oil companies, major pipeline
companies and their related marketing companies, and national and local gas
gatherers, processors and marketers. Competition not only exists for operating
margins but also for additional inlet volumes, obtaining gas supplies for
gathering and processing operation, obtaining supplies of raw product for
fractionation and the transportation of natural gas and NGLs.
The Company has responded to these industry conditions by acquiring assets, most
of which are strategically located by the Company's existing assets. The Company
has also responded, along with others in the industry, by reducing costs,
rationalizing assets in non-core operating areas and renegotiating contracts.
The principal goal of these efforts is to mitigate the variability of earnings
and cash flow caused by fluctuations in commodity prices.
8
The Company's strategy is to continue to build a vertically integrated natural
gas liquids infrastructure having the capability of maximizing profit throughout
the value chain extending from inlet natural gas volumes gathered from producing
areas in the U. S., primarily in portions of the Mid Continent region, to
marketing NGLs to wholesalers and end users. The Company, unlike most
competitors in the industry has the ability, through NGL storage facilities, to
store product.
The Gathering and Processing segment is subject to some seasonality. Some of the
products, such as propane, are used for heating, and accordingly, these products
are more in demand during the heating months of November through April.
Accordingly, the price of these products is typically higher in the winter due
to greater demand.
ACQUISITIONS - In April 2000, the Company acquired certain natural gas gathering
and processing assets from KMI. This acquisition included natural gas processing
plants with a capacity of 1.26 Bcf/d and 6,400 miles of gathering lines. The
current throughput of these gathering and processing assets is approximately
0.76 Bcf/d. Production of NGLs from these assets averages 33 MBbls/d. These
assets have had a positive impact on the Company's operating performance and
have complemented its current asset base.
In March 2000, the Company acquired natural gas processing plants with a
capacity of 375 MMcf/d and approximately 7,000 miles of gas gathering and
transmission pipeline systems from Dynegy. The current throughput of these
gathering and processing assets is approximately 240 MMcf/d. Production of
natural gas liquids from these assets averages 25 MBbls/d.
GOVERNMENT REGULATIONS - The FERC has traditionally maintained that a processing
plant is not a facility for transportation or sale for resale of natural gas in
interstate commerce and therefore is not subject to jurisdiction under the
Natural Gas Act (NGA). Although the FERC has made no specific declaration as to
the jurisdictional status of the Company's gas processing operations or
facilities, the Company believes its gas processing plants are primarily
involved in removing natural gas liquids and therefore exempt from FERC
jurisdiction.
The NGA exempts natural gas gathering facilities from the jurisdiction of the
FERC. Interstate transmission facilities, on the other hand, remain subject to
FERC jurisdiction. The FERC has historically distinguished between these two
types of facilities on a fact-specific basis. The Company believes its gathering
facilities and operations meet the current test used by the FERC to determine a
nonjurisdictional gathering facility status.
The states of Oklahoma, Kansas and Texas also have statutes regulating, in
various degrees, the gathering of gas in those states. In each state, regulation
is applied on a case by case basis if a complaint is filed against the gatherer
with the appropriate state regulatory agency.
RISK MANAGEMENT - Derivative instruments are used to minimize volatility in NGL
and natural gas prices. Accordingly, the Company uses derivative instruments to
hedge the price of natural gas purchased and used for processing and operations.
The Company also, from time to time, uses derivative instruments to secure a
certain price for their product. At December 31, 2000, the Gathering and
Processing segment was not a party to any derivative instruments used for
hedging purposes. See Item 7A. Quantitative and Qualitative Disclosures About
Market Risk and Footnote C to the Notes to the Consolidated Financial
Statements.
The Company also manages price risk of commodity products through the use of
certain natural gas processing contracts. During 2000, the Company restructured
its contract mix to reduce the number of Keep Whole contracts from 35 percent of
its contract mix to 32 percent. This restructuring effort reduced the Company's
exposure to greater margin volatility that exists primarily through "Keep Whole"
contracts.
9
(C) TRANSPORTATION AND STORAGE
GENERAL - ONEOK's Transportation and Storage segment provides intrastate natural
gas pipeline transportation and storage for Oklahoma, Kansas, and Texas with the
major customer being ONEOK's Distribution segment in both Oklahoma and Kansas.
The Company conducts this business primarily through wholly owned intrastate
pipeline companies with a total of 9,689 miles of pipe and wholly owned storage
companies with a total capacity of approximately 58 Bcf.
In Oklahoma, the Company operates OGT, Sayre and OGS. These companies have
approximately 3,245 miles of pipeline and their five storage facilities have a
combined storage capacity of 43 Bcf. Capacity in the storage facilities is
leased to both OEMT and third parties under various terms. The Sayre gas storage
facility is leased on a long term basis to and operated by Natural Gas Pipeline
Company of America. The Company retains three Bcf of capacity in the Sayre
facility for its own use. A $3.4 million expansion to increase deliverability
from the Depew storage field was completed in the spring of 2000.
The Oklahoma transmission system transported 299.1 Bcf in 2000 and 234.9 Bcf in
1999. OGT provides access to the major natural gas producing areas in Oklahoma.
The system intersects with 10 intra/interstate pipelines at 26 interconnect
points, 21 processing plants, and approximately 130 producing fields effectively
allowing gas to be moved throughout the state.
In Kansas, ONEOK operates as MCMC and MCTI with 1,711 miles of pipeline and two
gas storage facilities with approximately 5.0 Bcf of capacity. A $10 million
expansion of the Kansas transmission system was completed during 2000, which
connects the MCMC system to the Bushton natural gas processing facility, which
the Company acquired the lease on in 2000, Northern Natural Gas, and ANR
Pipeline. The Kansas transmission system transported 87.1 Bcf in 2000 and 72.8
Bcf in 1999. MCMC and MCTI provide access to the major natural gas producing
areas in Kansas. The system intersects with ten intra/interstate pipelines at 13
interconnect points, five processing plants, and approximately three producing
fields effectively allowing gas to be moved throughout the state.
In Texas, ONEOK operates WesTex with approximately 4,733 miles of pipeline and
ONEOK Texas Gas Storage with storage capacity of approximately 10 Bcf. This
system was acquired from KMI in April 2000. The Texas transmission system
transported 170.8 Bcf in 2000. WesTex provides access to the major natural gas
producing areas in the Texas Panhandle and the Permian Basin. The system
intersects with 11 intra/interstate pipelines at 32 interconnect points, 11
natural gas processing plants, and approximately two producing fields
effectively allowing gas to be moved to the Waha Hub for transportation to the
West, including California. This pipeline allows the Company to provide service
to the city of El Paso, Texas.
A small amount of gathering pipelines owned by the Company and connected to the
Company's transmission pipelines are included in this segment.
Of the Company's consolidated revenues, revenues from the Transportation and
Storage segment represent approximately 1.7, 1.5 and 0.9 percent for fiscal
years 2000, 1999 and 1998, respectively. Operating income from the
Transportation and Storage segment is 18.6, 27.9, and 24.8 percent of the
consolidated operating income for fiscal years 2000, 1999, and 1998,
respectively.
MARKET CONDITIONS AND SEASONALITY - The Transportation and Storage segment
competes directly with other intrastate and interstate pipelines and storage
facilities within each of their respective states. Competition for
transportation services continues to increase as the FERC and state regulatory
bodies enact legislation to introduce more competition in the natural gas
markets.
10
The Transportation and Storage segment is subject to some seasonality. Volumes
transported are slightly higher in the heating season since some customers
transport volumes for heating needs. Historically, customers and the Company
purchased and stored gas in the summer months when prices were lower and
withdrew gas during the heating season; however, the increase of gas-fired
electric generating plants and increased volatility in the natural gas market
has lead to increased demand for natural gas in the summer months which is
expected to change gas storage practices.
GOVERNMENT REGULATIONS - The regulatory structure that has historically applied
to the natural gas industry has been in a state of transition throughout the
last decade and continues to be. The Company continues to pursue deregulation of
its assets with the respective state regulatory bodies in an effort to maximize
shareholder return and provide reliable service at fair prices to its customers.
The Company received a final order from the OCC in the second quarter of 2000
that separated the distribution assets of ONG and the transmission assets of OGT
and related affiliates into two separate public utilities. This order also
adjusted ONG's rates for the removal of the gathering, transmission and storage
assets, and established a competitive bid process for ONG's upstream service.
Through the competitive bid process, OGT retained approximately 96 percent of
ONG's upstream transportation requirements.
Effective November 1, 1999, by order from the OCC, the Company's gathering and
storage assets and services in Oklahoma were removed from utility regulation.
Assets, including current gas in storage, of $325.0 million were removed from
the Oklahoma customers' rate base and are now included in this segment where
they are being utilized in the competitive market place. In 2000, a portion of
the return on rate base related to these storage assets was recovered from the
distribution customers through the Purchased Gas Adjustment (PGA) for
maintaining current working gas in storage. Approximately $3.5 million will be
recovered annually from the distribution customers through a Gathering Rider.
The Company's transportation and storage assets in Kansas are regulated by the
KCC. The Company has flexibility in establishing transportation rates with
customers; however, there is a maximum rate that MCMC can charge its customers.
The Company's transportation and storage assets located in Texas are regulated
by the TRC. The Company has flexibility in establishing transportation rates
with customers; however, if a rate cannot be agreed upon, the rate is
established by the TRC.
CUSTOMERS - The Transportation and Storage segment serves the affiliated
companies of the Distribution segment and Marketing and Trading segment as well
as a number of transporters in the utilization of the transportation and storage
facilities. Each of the companies provides flexible service alternatives to
serve both core and non-core consumers. The Transportation and Storage segment
serves a diverse group of customers, including affiliates. In November 2000, the
Company announced the execution of long term agreements between OGT and Duke
Energy North America (DENA) for firm transportation service to DENA's gas fueled
McClain Energy Facility in the amount of 85 MMcf/d.
ACQUISITIONS - The Company acquired transportation and storage assets located in
Texas from KMI in April 2000. These assets are deemed strategic assets to the
Company in part since they give the Company access to an expanded area in the
Texas and the California markets.
(D) DISTRIBUTION
GENERAL - ONG distributes natural gas to wholesale and retail customers located
in the state of Oklahoma. ONG delivered natural gas to approximately 809,000
customers at December 31, 2000, located in 325 communities in Oklahoma. ONG's
largest markets are the Oklahoma City and Tulsa metropolitan areas. ONG also
sells natural gas to other local gas distributors serving 44 Oklahoma
communities. ONG serves an estimated population of over 2.5 million. During
2000, the Oklahoma customers of KGS were removed from KGS and became ONG
customers.
11
KGS supplies natural gas to approximately 634,000 customers in 368 communities
in Kansas. It also makes wholesale delivery to 17 customers. KGS's largest
markets served include Wichita, Topeka, and Johnson County, which includes
Overland Park, Kansas.
Of the Company's consolidated revenues, revenues from the Distribution segment
represent approximately 19.1, 49.8 and 52.9 percent for fiscal years 2000, 1999,
and 1998, respectively. Operating income from the Distribution segment is 29.3,
45.5, and 54.9 percent of the consolidated operating income for fiscal years
2000, 1999, and 1998, respectively.
GAS SUPPLY - Gas supplies available to ONG for purchase and resale include
supplies of gas under both short and long-term contracts with gas marketers and
independent producers. Oklahoma is the third largest gas producing state in the
nation, and ONG has direct access through the Transportation and Storage
segment's transmission system and transmission systems belonging to third party
companies to all of the major gas producing areas in Oklahoma. The Company's gas
storage, transportation and gathering assets were unbundled from the utility and
now operate as separate entities. Gas supply and transportation bids were
awarded for service beginning in the 2000/2001 heating season for two and five
year terms. As a result of the process, the majority of the Company's gas supply
and gas transportation needs will continue to be met by two affiliates, OEMT for
supply, and OGT for upstream transportation service.
KGS has transportation agreements for delivery of gas that have terms varying
from one to twenty years with the following non-affiliated pipeline transmission
companies: Williams Gas Pipelines Central, Inc. (WGPC), Kansas Pipeline Company,
Kinder Morgan Interstate Gas Transmission, L.L.C., Panhandle Eastern Pipeline
Company, Northern Natural Gas Company and Natural Gas Pipeline of America.
Additionally, approximately 25 percent of KGS's transportation service is
provided by the affiliated intrastate pipeline company, MCMC.
KGS has a long-term gas purchase contract (Base Contract) with Amoco Production
Company (Amoco) for the purpose of meeting the requirements of the customers
served over the WGPC pipeline system. The Company anticipates that the Base
Contract will supply between 50 percent and 65 percent of KGS's demand served by
the WGPC pipeline system. Amoco is one of various suppliers over the WGPC
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 that exceeds the needs of the Company's residential and
commercial customer base is also available for sale to other parties (as
available gas sales).
For the remainder of KGS's supply, the gas is purchased from a combination of
direct wellhead production, natural gas processing plants, and natural gas
marketers and production companies.
There is an adequate supply of natural gas available to its utility systems and
the Company does not anticipate problems with securing additional gas supply as
needed for its customers. However, if supply shortages occur, ONG's rate
schedule "Order of Curtailment" and the KGS rate order "Priority of Service"
provide for first reducing or totally discontinuing gas service to 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.
CUSTOMERS - RESIDENTIAL AND COMMERCIAL - ONG and KGS distribute natural gas as
public utilities to approximately 80 percent of Oklahoma's gas retail markets
and 67 percent of Kansas' gas retail markets. Natural gas sales to residential
and commercial customers, which are used primarily for heating and cooking,
account for approximately 65 and 29 percent of gas sales, respectively in
Oklahoma and 76 and 23 percent of gas sales in Kansas, respectively.
12
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
in 58 municipalities including Tulsa and Oklahoma City while KGS holds
franchises in 368 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 - Under the Company's pipeline capacity lease (PCL) program and
transportation program, certain customers, for a fee, can have their gas,
whether purchased from ONG or a third-party supplier, transported to its
facilities utilizing lines owned by ONG or its affiliates. As contracts with PCL
and transportation customers expire and there is increased competition for the
transportation of gas to these customers, some of these customers may be lost to
affiliates or third party transporters. The Transportation and Storage segment
may gain some of this business that would result in a shift of some revenues
from the Distribution segment to the Transportation and Storage segment.
KGS transports gas for its large industrial customers through its End-Use
Customer Transportation (ECT) program. This program allows industrial customers
to purchase gas on the spot market and have it transported by KGS.
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. No single customer accounted for more than ten
percent of consolidated operating revenues.
COMPETITION AND BUSINESS SEASONALITY - The natural gas industry is expected to
remain highly competitive resulting from deregulation and unbundling initiatives
being pursued by the industry and regulatory agencies. 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 and large industrial markets. In
residential markets, the average cost of gas is less for ONG and KGS customers
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 offered by ONG, in response to such competitive
pressure, allows ONG to effectively compete in these markets and maintain
throughput and therefore, load factors that 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 lower rates. Unbundling is another response to competition. A
competitive bidding system, made possible by the unbundling of services, and
more customer choice provides the opportunity for lower costs for the consumer.
Gas sales to residential and commercial customers are seasonal, as a substantial
portion of gas is used principally for space heating. Accordingly, the volume of
gas sales is consistently higher during the heating season (November through
April) than in other months of the year. ONG's tariff rates include a
temperature normalization adjustment clause during the heating season which
mitigates the effect of fluctuations in weather. The WeatherProof Bill program,
implemented in September, 1999, and permanent in 2000, is designed to mitigate
the effect of weather fluctuations in Kansas for customers electing to use this
program. KGS also implemented a weather normalization clause in December 2000
that will mitigate the effect of fluctuations in weather.
ONG's PCL and transportation services and some of KGS's ECT services are at
negotiated rates that are generally below the approved PCL tariff rates, and
increased competition potentially could lower these rates. Industrial sales and
rentals for PCL's tend to remain relatively constant throughout the year.
13
GOVERNMENT REGULATIONS - Rates charged for gas services are established by the
OCC for ONG and by the KCC for KGS. Gas purchase costs are included in the PGA
clause that is billed to customers. The Company does not make a profit on the
cost of gas. Other costs must be recovered through periodic rate adjustments
approved by the OCC and KCC.
A rate case was settled between ONG and the OCC on May 30, 2000 in Oklahoma
resolving a number of regulatory and unbundling issues. The highlights of which
follow:
o A $57 million annual rate base reduction, effective with the
first billing cycle in June 2000, spread among all customer
classes. The PCL Rider was terminated and the $37.8 million
balance was moved to base rates and included in the revenue
reduction, thereby creating a net annual reduction of
approximately $20 million.
o Deregulation of gas storage and gas gathering and removal of
the related investments from the regulated Oklahoma
Distribution segment's rate base. The Company was allowed to
recover approximately $3.5 million annually from its
distribution customers through a Gathering Rider.
o Depreciation rates were decreased which will result in
recovery of approximately $10.5 million less in depreciation
expenses annually.
o ONG may defer the depreciation and operating and maintenance
associated with new service line programs. Under the new
service line programs ONG will begin assuming responsibility
for, and ownership of, customer service lines. The recovery
methodology applicable to the new service line program and
amount to be recovered will be addressed as a part of ONG's
next general rate filing.
o Oklahoma customers previously served by KGS were consolidated
with ONG. This will simplify the Company's regulatory
activities by allowing the KGS-Oklahoma customers to be served
under the ONG rate structure and by allowing the Company to
discontinue separate regulatory reporting and rate case
activity for KGS-Oklahoma. However, the Company did sustain an
annual margin reduction estimated at $2.3 million related to
this change since the previous KGS-Oklahoma rates were
generally higher than the comparable ONG rates that will now
apply to these customers.
o ONG and OGT will be considered as two separate regulated
utilities on a prospective basis. The two utility operations
will be able to function independently in pursuing their
respective targets and objectives.
During 2000, the KCC issued an Order allowing KGS to recover additional costs of
its gas purchase hedging program established to protect the price paid by
customers for gas purchases. The KCC also permanently approved KGS's
WeatherProof Bill Program that had been a pilot program. This plan allows
customers, at their discretion, to fix their monthly payment. The KCC also
granted the Company weather normalization beginning in December 2000 that
mitigates weather related revenue fluctuations.
The Company has settled all known claims arising out of long-term gas supply
contracts containing "take-or-pay" provisions that 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 Natural Gas Policy Act (NGPA) and other intrastate transportation revenues.
There are no significant potential claims or cases pending against the Company
under "take-or-pay" contracts.
OkTex Pipeline Company transports gas in interstate commerce under Section
311(a) of the NGPA and is treated as a separate entity by the FERC. Accordingly,
OkTex is subject to the regulatory jurisdiction of the FERC under the NGA with
respect to rates, accounts and records, the addition of facilities, the
extension of services in some cases, the abandonment of services and facilities,
the curtailment of gas deliveries and other matters. 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 WesTex system. OkTex has complied with the
requirements of Order 636.
14
In the first quarter of 2000, the FERC issued Order No. 637, which, among other
things, imposed additional reporting requirements, required changes to make
pipeline and secondary market services more comparable, removed the price caps
on secondary market capacity for a period of two years, allowed rates to be
based on seasonal or term differentiated factors and narrowed the applicability
of the regulatory right of first refusal to apply only the maximum rate
contracts. The Company's interstate pipelines implemented the new regulations in
May 2000. The FERC Order did not have a material effect on the Company's
operations.
(E) PRODUCTION
GENERAL - The Company's strategy is to concentrate ownership of natural gas and
oil reserves in the Mid Continent region in order to add value not only to its
existing production operations but also to integrate it into its gathering and
processing, marketing and trading, and transportation and storage businesses.
The Company continues to focus on growing through acquisitions and developing
existing properties.
Of the Company's consolidated revenues, revenues from the Production segment
represent approximately 0.7, 2.4, and 1.7 percent for fiscal years 2000, 1999,
and 1998, respectively. Operating income from the Production segment is 4.6,
6.3, and 5.7 percent of the consolidated operating income for fiscal years 2000,
1999, and 1998, respectively.
PRODUCING RESERVES - The Production segment primarily focuses its production
activities in natural gas to capitalize on the Company's assets. As of December
31, 2000, the Company had a working interest in 2,055 gas wells and 205 oil
wells located primarily in Oklahoma, Kansas and Texas. A number of these wells
produce from multiple zones. Production decreased in 2000 as compared to 1999,
as a result of the natural depletion of reserves that are not entirely replaced
through acquisitions or developmental drilling.
MARKET CONDITIONS AND BUSINESS SEASONALITY - Natural gas and oil prices have
been strong throughout much of 2000. At the end of 2000, natural gas prices
reached unprecedented highs. The increase in prices has prompted a significant
amount of drilling in the U.S. Accordingly, rig availability has delayed some
developmental drilling projects for the Company, as well as others in the
industry. In response to the industry wide shortage in rig availability, the
Company is focusing on partnering with drilling companies to increase reserves
through its developmental drilling strategy. The Company continues to assess
acquisition opportunities.
The goal of the Company is to develop an economically viable reserve base
through acquisition and development. The Company operates much 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. During 2000, most of the segment's production was sold to the
Marketing and Trading segment, Gathering and Processing segment and third party
markets, at market prices.
Similar to the Company's other business segments, the Production segment is
subject to seasonal factors on a limited basis. The Production segments revenues
are impacted partially by prices, which, historically, are higher in the winter
heating months when demand is higher than in the summer and shoulder months,
spring and fall. Oil prices in the U.S., including the Company's Production
segment, are also impacted by international production and export policies.
PROPERTY ACQUISITIONS AND DIVESTITURES - The Company acquired $4.8 million of
properties during 2000, located in a portion of the Mid Continent region of the
U.S. These strategically located properties will contribute to the Company's
strategy of acquiring assets that strengthen and complement each other.
In June 2000, the Company sold $6.0 million of non-core, non-strategic oil and
natural gas producing properties. The sale included 143 wells that were located
in isolated fields throughout Texas and parts of Oklahoma and Kansas.
15
RISK MANAGEMENT - The Production segment continues to utilize derivative
instruments in order to hedge anticipated sales of natural gas and oil
production. During 2000, production was hedged with commodity swap agreements
whereby the Company was able to set the price to be received for the future
production and 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 did not terminate a hedge or enter into an opposing derivative, the
strategy employed during 2000, limited earnings, which resulted from increases
in market prices above the level set by the hedge.
At December 31, 2000, the Company had approximately 74 percent of its proved
developed production hedged for fiscal year 2001. See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk and Note C to Notes to Consolidated
Financial Statements.
(F) OTHER
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.
ITEM 2. PROPERTIES
(A) DESCRIPTION OF PROPERTY
MARKETING AND TRADING
The Company is in the process of constructing a 300 megawatt gas-fired merchant
power plant located in Logan County, Oklahoma and adjacent to an affiliate's gas
storage facility. The Company expects this plant, configured to supply electric
power during peak periods, to be completed and operational in June 2001. To date
the Company has spent approximately $72 million on construction. Total estimated
cost of the project is $120 million.
GATHERING AND PROCESSING
The Company owns or leases and operates 25 natural gas processing plants, has
operating interests in four natural gas processing plants and owns related
gathering systems in Oklahoma, Texas and Kansas. Five of the Company owned
natural gas processing plants were idle in 2000. The Company's total capacity of
the plants the Company owns, leases or has an ownership interest in is 2.2
Bcf/d. The Company's natural gas processing operations are conducted at two
types of gas processing plants, field and straddle plants. Field plants
aggregate volumes from multiple producing wells into quantities that can be
economically processed to extract natural gas liquids and to remove water vapor,
solids and other contaminants. Straddle plants are situated on mainline natural
gas pipelines and allow operators to extract natural gas liquids under contract
from a natural gas stream when the market value of natural gas liquids separated
from the natural gas stream is higher than the market value of the same
unprocessed natural gas stream.
S 16
Following is a table providing certain information about the Company's natural
gas processing plants.
SUMMARY OF ONEOK GAS PROCESSING FACILITIES
PERCENT
PROCESSING LEASED OR COUNTY CAPACITY
FACILITIES OWNED (1) AND STATE (MMcf/d) (2)
Bushton 100 Ellsworth, KS 1,000.0
Scott City 100 Scott, KS 100.0
Maysville 70 Garvin, OK 94.5
Panther Creek 100 Custer,OK 90.0
Rodman 100 Garfield, OK 85.0
Cheney 100 Kingman, KS 85.0
Custer 100 Custer,OK 80.0
Stinnett 100 Moore, TX 80.0
Beaver (3) 100 Beaver, OK 75.0
El Reno 100 Canadian, OK 75.0
Woodward 100 Woodward, OK 75.0
Leedy 100 Roger Mills, OK 50.0
Arrington 100 Hemphill,TX 40.0
Antelope Hills 100 Roger Mills, OK 40.0
Cargray 100 Carson, TX 30.0
Stephens 100 Stephens, OK 30.0
Canadian 100 Hemphill,TX 25.0
Kingsmill (3) 100 Gray, TX 24.5
Ringwood 100 Major, OK 22.0
Carson (3) 100 Carson, TX 20.0
Gray 100 Gray, TX 20.0
Watonga (3) 100 Kingfisher, OK 15.0
Dover Hennessey 18.1 Kingfisher, OK 14.0
Fox 50 Carter, OK 12.5
Lefors 100 Gray, TX 11.0
Binger 100 Caddo, OK 10.0
Springer 100 Carter, OK 9.5
Kellerville (3) 100 Gray, TX 7.0
Spivey 5 Harper, TX 3.3
---------------
Total 2,223.3
===============
(1) ONEOK owns or leases the indicated percentage of an associated gathering
system
(2) Capacity data is at practical recovery rates, net to ONEOK's interest.
(3) Plant is currently idle.
17
Following is a table providing certain information about the Gathering and
Processing segment's storage and terminal facilities. The Bushton Rail and Truck
Terminals include an import/export terminal.
SUMMARY OF ONEOK STORAGE AND TERMINAL FACILITIES
Percent County Capacity
Facilities Owned and State (MBbls) Description
- --------------------------------------------------------------------------------
Bushton Storage 100 Ellsworth, KS 14,000 NGL storage facility
Bushton Rail and
Truck Terminals 100 Ellsworth, KS 110 Product terminal facility
Maysville Truck Terminal 70 Garvin, OK 60 Product terminal facility
Cargray Truck Terminal 100 Carson, TX 23 Product terminal facility
The Company's natural gas processing plants were operating at various capacities
throughout the year. At certain times throughout the year, the Company's natural
gas processing facilities operated at levels well below capacity due to the
historically high natural gas prices. When this occurred, some producers sold
their natural gas rather than having it processed into NGLs. If natural gas
prices stabilize in 2001, this should allow the Company to operate its natural
gas processing facilities at higher levels than in 2000. The Company is
rationalizing assets in non-core operating areas. In response to this, the
Company is moving certain assets to improve utilization of certain natural gas
processing plants. Overall, the plants operated at approximately 62 percent of
capacity.
The Company owns approximately 19,300 miles of gathering pipeline, some of which
are connected to the Company's natural gas processing plants.
TRANSPORTATION AND STORAGE
The Company owned a combined total of approximately 3,245 miles of transmission
pipeline in Oklahoma, approximately 1,711 miles in Kansas, and approximately
4,733 miles in Texas at December 31, 2000. Compression and dehydration
facilities are located at various points throughout the pipeline system. In
addition, the Company owns five underground storage facilities located
throughout Oklahoma, two storage facilities in Kansas and three storage
facilities in Texas. The storage facilities primarily consist of land and
mineral leasehold agreements, wells and equipment, rights of way, and cushion
gas. The total storage capacity of these facilities is approximately 58 Bcf.
Four of the Oklahoma storage facilities are located in close proximity to large
market areas; the other storage facility is located in western Oklahoma and is
leased to and operated by another company. However, three Bcf of storage
capacity in that facility has been retained for use by the Company. The storage
facilities in Kansas and Texas are connected to the Company's pipelines and are
located near third party intrastate and interstate pipelines, providing the
Company's storage customers with access to multiple markets.
Following is a table providing certain information about the Transportation and
Storage segment's storage facilities.
COUNTY CAPACITY
FACILITIES AND STATE (MMcf)
- -----------------------------------------------------------------
Depew Creek, OK 19,153
Edmond Logan and Kingfisher, OK 16,416
Haskell Muskogee, OK 3,587
Osage Osage, OK 912
Sayre Beckham, OK 3,000
Brehm Pratt, KS 1,989
Yaggy Reno, KS 2,993
Felmac Gaines, TX 1,989
Loop Gaines, TX 4,973
Salado Gaines, TX 2,924
------------
57,936
18
DISTRIBUTION
The Company owned approximately 16,126 miles of pipeline and other distribution
facilities in Oklahoma and approximately 12,734 miles of pipeline and other
distribution facilities in Kansas at December 31, 2000. The Company owns 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 and maintains an inventory of spare parts, equipment, and
supplies.
PRODUCTION
The Company owns varying economic interests, including working, royalty and
overriding royalty interests, in 2,055 gas wells and 205 oil wells, some of
which are completed in multiple producing zones. Such interests are in wells
located primarily in Oklahoma, Kansas, and Texas. The Company owns 185,847 net
onshore developed leasehold acres and 37,421 net onshore undeveloped acres,
located primarily in Oklahoma, Kansas, and Texas. The Company does not own any
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.
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
the primary term or any renewal period, the Company can purchase the property at
its fair market value. The Company occupies approximately 194,000 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
gathering and processing operation produces natural gas liquids. The SEC
excludes the production of natural gas liquids resulting from the operations of
gas processing plants as an oil and 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 S of Notes to Consolidated
Financial Statements.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES - See Note T of Notes to
Consolidated Financial Statements.
RESERVE ESTIMATES FILED WITH OTHERS
None.
19
QUANTITIES OF OIL AND GAS PRODUCED
The net quantities of oil and natural gas produced and sold, including
intercompany transactions, were as follows:
Years Ended
December 31, August 31,
Sales 2000 1999 1998
- ----------------------------------------------
Oil (MBbls) 400.0 460.0 330.0
Gas (MMcf) 26,746.0 27,773.0 16,818.0
- ----------------------------------------------
Four Months Ended
December 31,
Sales 1999 1998
- ----------------------------------------------
Oil (MBbls) 138.0 145.0
Gas (MMcf) 8,306.0 7,700.0
- ----------------------------------------------
AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS
Average sales prices and production costs are as follows:
Years Ended
December 31, August 31,
2000 1999 1998
- ------------------------------------------------------
Average Sales Price (a)
Per Bbl of oil $ 21.43 $ 13.56 $ 15.70
Per Mcf of gas $ 2.28 $ 2.12 $ 2.21
Average Production Costs
Per Mcfe (b) $ 0.60 $ 0.49 $ 0.50
- ------------------------------------------------------
Four Months Ended
December 31,
1999 1998
- ----------------------------------------------
Average Sales Price (a)
Per Bbl of oil $ 18.93 $ 12.53
Per Mcf of gas $ 2.50 $ 2.03
Average Production Costs
Per Mcfe (b) $ 0.60 $ 0.46
- ----------------------------------------------
(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 Mcfs of natural gas
to one barrel of oil. Production costs are based on the wellhead market price,
which averaged $29.34 per Bbl of oil and $3.42 per Mcf of gas in 2000 and $16.95
per Bbl of oil and $2.13 per Mcf of gas in 1999, contributing to the significant
increase in average production costs per Mcfe. Production costs do not include
depreciation or depletion.
20
WELLS AND DEVELOPED ACREAGE
The table shows gross and net wells in which the Company has a working interest
at December 31, 2000.
Gas Oil
- ---------------------------
Gross wells 2,055 205
Net wells 596 76
- ---------------------------
Gross developed acres and net developed acres by well classification are not
available. Net developed acres for both oil and gas is 185,847 acres.
UNDEVELOPED ACREAGE
The gross and net undeveloped leasehold acreage at the end of the fiscal year is
as follows:
Gross Net
- --------------------------------------
Colorado 1,425 296
Kansas 1,068 538
Mississippi 2 1
Oklahoma 117,638 35,459
Texas 3,825 1,127
- --------------------------------------
Of the net undeveloped acres, approximately 37 percent lies in the Anadarko
Basin area of Oklahoma and Texas, 20 percent in the Arkoma Basin area of
Oklahoma and 7 percent in the Ardmore Basin area of Oklahoma. The balance is
located in major producing areas in other states including Kansas, Texas and
Colorado.
NET DEVELOPMENT WELLS DRILLED
The net interest in total development wells drilled, by well classification, is
as follows:
Years Ended
December 31, August 31,
2000 1999 1998
- ----------------------------------------------
Development
Productive 28.5 22.5 14.0
Dry 1.8 1.4 0.6
- ----------------------------------------------
Total 30.3 23.9 14.6
Four Months Ended
December 31,
1999 1998
- ---------------------------------------------------------------
Development
Productive 9.6 8.2
Dry 0.0 0.1
- ---------------------------------------------------------------
Total 9.6 8.3
21
PRESENT DRILLING ACTIVITIES
On December 31, 2000, the Company was participating in the drilling of 33 wells.
The Company's net interest in these wells amounts to 12 wells.
FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS
None.
22
ITEM 3. LEGAL PROCEEDINGS
UNITED STATES EX REL. JACK J. GRYNBERG V. ONEOK, INC., ONEOK RESOURCES COMPANY,
AND OKLAHOMA NATURAL GAS COMPANY, (CTN-8), NO. CIV-97-1006-R, UNITED STATES
DISTRICT COURT FOR THE WESTERN DISTRICT OF OKLAHOMA, TRANSFERRED, IN RE NATURAL
GAS ROYALTIES QUI TAM LITIGATION, MDL DOCKET NO. 1293, UNITED STATES DISTRICT
COURT FOR THE DISTRICT OF WYOMING. ONEOK received the complaint on June 21,
1999. The complaint makes claims to recover alleged underpayments of royalties
to the United States as a result of improper measurement of heating contents and
volumes of natural gas which was purchased from federally owned or Indian lands
by ONEOK, Inc., ONEOK Resources Company, and Oklahoma Natural Gas Company
(collectively, the "ONEOK Defendants"). This case is what is known as a qui tam
action which was brought by the plaintiff relator on behalf of the United States
and himself. The complaint asserts essentially the same claims that the same
plaintiff relator, Jack J. Grynberg ("Grynberg"), asserted in a previous action
(United States et rel. Jack J. Grynberg v. Alaska Pipeline Company, et al., No.
95-725-TFH, in the United States District Court for the District of Columbia)
against the ONEOK Defendants and approximately sixty-five other pipeline
companies. In the case, on behalf of the United States, Grynberg seeks to
receive the proceeds for the underpayment of royalties, interest, treble
damages, and civil penalties in the amount of $5,000 to $10,000 for each
violation of the Act. Grynberg also seeks to receive his expenses incurred in
bringing the action, plus attorney fees and costs. In addition, Grynberg has
asserted claims for underpayment of royalties based upon generalized allegations
of use of a portable chromatograph, affiliate transactions, use of storage
facilities to purchase gas in summer months, and improper deduction of costs. A
motion to dismiss the action was filed on behalf of the defendants. The
defendants have also requested a stay of discovery pending resolution of the
motion to dismiss. A hearing on the motion to dismiss was held on March 17,
2000. The Court is also considering the motion to stay discovery, which was
argued at a status/scheduling conference held on December 15, 1999. There has
not been a ruling on the motion to dismiss.
ONEOK, INC. V. SOUTHERN UNION COMPANY, NO. 99-CV-0345-H(M), UNITED STATES
DISTRICT COURT FOR THE NORTHERN DISTRICT OF OKLAHOMA, TRANSFERRED, NO. CV 00-
1812-PHX-ROS, IN THE UNITED STATES DISTRICT COURT FOR THE DISTRICT OF ARIZONA,
ON APPEAL OF PRELIMINARY INJUNCTION, UNITED STATES COURT OF APPEALS FOR THE
TENTH CIRCUIT, CASE NUMBER 99-5103. On May 5, 1999, ONEOK filed a complaint
against Southern Union Company ("Southern Union") for breaching the February 21,
1999 confidentiality and standstill agreement between Southern Union and
Southwest Gas Corporation ("Southwest"). ONEOK is a third-party beneficiary.
ONEOK also sought to enjoin Southern Union from breaching the confidentiality
and standstill agreement and from taking any other wrongful actions to disrupt
the proposed merger of ONEOK with Southwest. On May 11, 1999, the District Court
granted a temporary restraining order enjoining Southern Union from any future
violation of its confidentiality and standstill agreement with Southwest,
including soliciting proxies from Southwest shareholders. On May 17, 1999, the
temporary restraining order became a preliminary injunction by stipulation of
the parties and was appealed to the Tenth Circuit Court of Appeals. Southern
Union filed its answer to the complaint on September 7, 1999, withdrawing some
specific allegations of wrongdoing that it made in an earlier filing. Southern
Union filed an amended answer and counterclaims on November 10, 1999. Southern
Union's counterclaims against ONEOK are for: (1) a declaratory judgment
determining that the confidentiality and standstill agreement was unenforceable;
and (2) a declaratory judgment determining that Southern Union had not breached
the confidentiality and standstill agreement. The Court held a status conference
on August 31, 2000, and granted Southern Union's pending Motion to Transfer the
action to the federal district court in Arizona. Discovery has been proceeding
in the cases. Based on the transfer of the case to Arizona, on February 2, 2001,
the Tenth Circuit dismissed Southern Union's appeal of the preliminary
injunction for want of appellate jurisdiction.
SOUTHERN UNION COMPANY V. SOUTHWEST GAS CORPORATION, ET AL., NO.
CIV-99-1294-PHX-ROS, UNITED STATES DISTRICT COURT FOR THE DISTRICT OF ARIZONA.
On July 19, 1999, the plaintiff, Southern Union Gas Company ("Southern Union"),
filed its complaint against Southwest Gas Corporation ("Southwest"), ONEOK, Inc.
("ONEOK"), Michael O. Maffie, Thomas Y. Hartley and Thomas R. Sheets (jointly
"Southwest Individual Defendants") and Eugene N. Dubay and John A. Gaberino, Jr.
(jointly "ONEOK Individual Defendants"), James M. Irvin ("Irvin") and Jack D.
Rose ("Rose"). Southern Union alleged (1) that the action arose out of a fraud
and
23
racketeering scheme by Southwest and ONEOK and the individual defendants to
block Southwest's shareholders from voting for Southern Union's offer to acquire
Southwest and ensure that only ONEOK's offer would be approved, (2) the
defendants entered into a secret campaign of deception, corruption and
misrepresentation with members of regulatory commissions in order to influence
their vote on the Southern Union proposal to acquire Southwest and to mislead
the board and shareholders of Southwest to believe falsely that such an
acquisition would face greater regulatory hurdles than the proposed Southwest-
ONEOK merger, (3) Southwest and Southwest Individual Defendants fraudulently
induced Southern Union to enter into a Confidentiality and Standstill Agreement
(the "Agreement") with Southwest, and (4) that corruption and fraud were
necessary to defeat the Southern Union offer. The complaint alleged numerous
causes of action including (1) racketeering in violation of 18 U.S.C. ss.1962(c)
and 1962(d), and unlawful activity in violation of Arizona Criminal Code through
a pattern of unlawful activities predicated on acts of extortion and a scheme or
artifice to defraud against all defendants and conspiracy (the "RICO claims"),
(2) fraud in the inducement, breach of contract, violation of the Securities
Exchange Act of 1934, breach of covenant of good faith and fair dealing and
rescission of the Agreement against Southwest, and (3) intentional interference
with a business relationship and tortious interference of a contractual
relationship against ONEOK, the ONEOK Individual Defendants, the Southwest
Individual Defendants, Rose and Irvin. The complaint asked for the award of an
amount of not less than $750,000,000 to be trebled for racketeering and unlawful
violations (with attorneys' fees and investigators' fees); compensatory damages
of not less than $750,000,000 for fraud in the inducement, breach of contract,
breach of covenant of good faith and fair dealing, intentional interference with
a business relationship, tortious interference with contractual relationship and
civil conspiracy (with interest and costs); rescission of the Agreement (with
costs), punitive damages, injunctive relief under the Securities Act of 1934 and
any further relief the court deems just and proper. Thomas R. Sheets was later
dismissed as a defendant by Southern Union. As a result of motions to dismiss
being filed by certain defendants, on October 12, 1999, Southern Union filed its
First Amended Verified Complaint (the "Amended Complaint"). The Amended
Complaint asserted many of the same claims as the earlier Complaint. Larry
Brummett and Jim Kneale were added as named defendants to the action. On May 30,
2000, Southern Union filed a dismissal with prejudice of its claims against
Larry Brummett. The Court granted leave to Southern Union to file its Second
Amended Complaint on August 3, 2000, but further ordered that Southern Union
could make no further amendments to its complaint. The Second Amended Complaint
alleged essentially the same claims as the earlier Complaint. On August 4, 2000,
the Court heard arguments on the defendants' motions to dismiss the federal and
state RICO claims, the motions of ONEOK and Southwest to dismiss or stay the
action because of previously filed actions, the motions to dismiss for lack of
personal jurisdiction filed by several of the individual defendants, and the
motion to dismiss filed by Jim Irvin on sovereign immunity grounds. Southern
Union orally made a motion at the hearing to dismiss without prejudice its
federal and state RICO claims against the ONEOK Individual Defendants which was
granted by the Court. On August 28, 2000, the Court entered an order denying the
motions to dismiss for lack of personal jurisdiction filed on behalf of Gene
Dubay and John Gaberino, but granted the motion filed on behalf of Jim Kneale.
On that same day, the Court entered an order denying the motion to dismiss filed
by Jim Irvin on sovereign immunity grounds. The Court also entered an order
denying the defendants' motions to dismiss the federal and state RICO claims on
the grounds that they were precluded by the Private Securities Litigation Reform
Act. On August 24, 2000, ONEOK and all the other defendants filed Motions to
Dismiss the claims asserted by Southern Union in its Second Amended Complaint.
On December 15, 2000, the Court withdrew its previous order of August 28, 2000,
and granted the motions of ONEOK and Southwest to dismiss the federal RICO
claims made by Southern Union on the ground that they were precluded by the
Private Securities Litigation Reform Act. Motions have been filed to apply the
Court's December 15 ruling to the other defendants and to Southern Union's state
RICO claims. On January 12, 2001, the Special Master heard oral argument on the
remaining Motions to Dismiss, and on March 21, 2001, entered a report and
recommendation that Judge Silver deny all of those motions (with the exception
of defendant Thomas Y. Hartley's Motion to Dismiss Southern Union's fraudulent
inducement claim, which the Special Master recommended should be granted);
objections to the report and recommendations may be filed by April 6, 2001, and
ONEOK and the ONEOK officers intend to file objections. Discovery in the case is
ongoing.
ONEOK, INC. V. SOUTHWEST GAS CORPORATION, NO. 00-CV-063-H(E), UNITED STATES
DISTRICT COURT FOR THE NORTHERN DISTRICT OF OKLAHOMA, TRANSFERRED, NO. CIV-00-
1775-PHX-ROS, UNITED STATES DISTRICT COURT FOR THE DISTRICT OF ARIZONA. On
January 21, 2000, as a result of its termination of the agreement for the merger
of ONEOK and Southwest Gas Corporation ("Southwest"), ONEOK brought this action
against Southwest seeking a declaratory judgment determining that it had
properly terminated the merger agreement. On March 6, 2000, Southwest filed a
motion seeking either a dismissal of the action or a transfer to the federal
court in Arizona. At a status conference held on August 31, 2000, the Court
heard argument on and granted Southwest's pending Motion to Transfer the action
to the federal district court in
24
Arizona. Southwest's response to ONEOK's First Amended Complaint will be due on
or before March 30, 2001. Discovery in the case is ongoing.
SOUTHWEST GAS CORPORATION V. ONEOK, INC. CIV-00-0119-PHX-ROS, UNITED STATES
DISTRICT COURT FOR THE DISTRICT OF ARIZONA. On January 24, 2000, Southwest
Gas Corporation ("Southwest") filed a complaint against ONEOK and Southern Union
Company ("Southern Union"). Southwest alleges that: (1) under the merger
agreement between ONEOK and Southwest, ONEOK agreed to furnish all information
concerning itself that is required or customary for inclusion in the Southwest
proxy statement related to the merger and that none of such information would
contain any untrue statement of material facts or omit to state any material
facts required to be stated therein or necessary to make the statements therein
in light of the circumstances under which they are made, not misleading; (2)
under the merger agreement ONEOK promised to use its commercially reasonable
efforts to obtain all necessary governmental authorization for the merger (and
consult with Southwest in respect thereto) and to take all other necessary
actions and do all things necessary, proper or advisable to consummate and make
effective the merger transaction; (3) ONEOK failed to disclose to the Southwest
Board that (i) ONEOK had participated in improper lobbying efforts in support of
ONEOK's bid for commissioner concerning regulatory approval; (ii) ONEOK's
improper involvement in efforts to lobby regulators in Arizona, California and
Nevada; and (iii) certain relationships involving a former employee of the
Arizona commission, all of which breached the merger agreement; (4) if ONEOK had
disclosed such lobbying efforts and relationships, it would have caused the
Board of Southwest to have serious questions about the integrity of ONEOK's
senior management and the chances of obtaining regulatory approvals, the
Southwest Board would not have entered into an amendment of the merger agreement
without answers to such questions and the Board would have demanded ONEOK cure
its breach of the merger agreement; (5) ONEOK's failure to make full and
truthful disclosure of such lobbying and relationships and the providing of
false information and misleading answers to the Arizona Corporation Commission
resulted in the staff withdrawing its support for the merger citing concerns
over the integrity, veracity and fitness of ONEOK and as a result, ONEOK failed
to use its commercially reasonable efforts to obtain such approval as required
by the merger agreement; and (6) ONEOK has refused to cure its breach of and has
wrongfully terminated the merger agreement. The complaint alleges numerous
causes of action including: (1) fraud in the inducement; (2) fraud; (3) breach
of contract; (4) breach of implied covenant of good faith and fair dealing; and
(5) declaratory relief. The complaint asks that the merger agreement be declared
null and void and Southwest be awarded its actual, consequential, incidental and
punitive damages in an amount in excess of $75,000 for fraud in the inducement
and fraud or alternatively (1) damages for breach of the contract and implied
covenant in an amount in excess of $75,000, or (2) a declaration that ONEOK has
breached the merger agreement. On February 28, 2000, Southern Union filed its
Answer to the Complaint denying the claims made by Southwest. ONEOK's response
to Southwest's Complaint will be due on March 30, 2001. Discovery in the case is
ongoing.
IN RE ONEOK, INC. DERIVATIVE LITIGATION, NO. CJ-2000-00593, DISTRICT COURT OF
TULSA COUNTY, OKLAHOMA (FORMERLY GAETAN LAVALLA, DERIVATIVELY ON BEHALF OF
NOMINAL DEFENDANT ONEOK, INC. V. LARRY W. BRUMMETT, ET AL., NO. CJ-2000-598 AND
HAYWARD LANE, DERIVATIVELY ON BEHALF OF NOMINAL DEFENDANT ONEOK, INC. V. LARRY
W. BRUMMETT, ET AL.). On February 3, 2000, two substantially identical
derivative actions were filed in the District Court in Tulsa, Oklahoma, by
shareholders against the members of the Board of Directors of ONEOK for
violation of their fiduciary duties to ONEOK by allegedly causing or allowing
ONEOK to engage in fraudulent and improper schemes designed to "sabotage"
Southern Union Company's ("Southern Union") competitive bid to acquire Southwest
Gas Corporation ("Southwest") and secure regulatory approval for ONEOK's own
planned merger with Southwest. Such conduct allegedly caused ONEOK to be sued by
both Southwest and Southern Union which exposed ONEOK to millions of dollars in
liabilities. The allegations are used as a basis for causes of action for
intentional breach of fiduciary duty, derivative claim for negligent breach of
fiduciary duty, class and derivative claims for constructive fraud, and
derivative claims for gross mismanagement. Each plaintiff seeks a declaration
that the lawsuit is properly maintained as a derivative action, the defendants,
and each of them, have breached their fiduciary duties to ONEOK, an injunction
permanently enjoining defendants from further abuse of control and committing of
gross mismanagement and constructive fraud, and asks for an award of
compensatory and punitive damages and costs, disbursements and reasonable
attorney fees. A Joint Motion for Consolidation of both derivative actions was
filed on June 6, 2000, and Pretrial Order No. 1 was entered on that date
consolidating the actions and establishing a schedule for a response to a
consolidated petition. On July 21, 2000, the plaintiffs filed their Consolidated
Petition. Stephen J. Jatras and J.M. Graves have been eliminated as
25
defendants in the Consolidated Petition, but Eugene Dubay was added as a new
defendant. The plaintiffs also dropped their class and derivative claim for
constructive fraud, but added a new derivative claim for waste of corporate
assets. On September 19, 2000, ONEOK, the Independent Directors (Anderson, Bell,
Cummings, Ford, Fricke, Lake, Mackie, Newsom, Parker, Scott and Young), David
Kyle, and Gene Dubay filed Motions to Dismiss the action for failure of the
plaintiffs to make a pre-suit demand on ONEOK's Board of Directors. In addition,
the Independent Directors, David Kyle, and Gene Dubay filed Motions to Dismiss
the Plaintiffs' Consolidated Petition for failure to state a claim. On
January 3, 2001, the Court dismissed the action without prejudice as to its
claims against Larry Brummett. On February 26, 2001, the action was stayed until
one of the parties notifies the court that a dissolution of the stay is
requested.
SWITZER, ET AL., V. CHEVRON U.S.A., INC., DYNEGY MIDSTREAM SERVICES, LTD., AND
DYNEGY MIDSTREAM, L.L.C., CASE NO. CIV-00-478-R, IN THE UNITED STATES DISTRICT
COURT FOR THE WESTERN DISTRICT OF OKLAHOMA. Upon motion of the Plaintiffs, the
subsidiary of ONEOK that was a defendant was dismissed from the case pursuant to
the Court's Order of Dismissal Without Prejudice, dated January 8, 2001.
LOYD SMITH, ET AL V. KANSAS GAS SERVICE COMPANY, INC. ONEOK, INC. WESTERN
RESOURCES, INC., MID CONTINENT MARKET CENTER, INC., ONEOK GAS STORAGE, L.L.C.,
ONEOK GAS STORAGE HOLDINGS, INC., AND ONEOK GAS TRANSPORTATION, L.L.C., CASE NO.
01C0029, IN THE DISTRICT COURT OF RENO COUNTY, KANSAS, AND MANAGEMENT RESOURCES,
GROUP, L.L.C., ET AL. VS. KANSAS GAS SERVICE COMPANY, ONEOK, INC., ONEOK GAS
STORAGE, L.L.C., ONEOK GAS STORAGE HOLDINGS, INC., ONEOK TRANSPORTATION, L.L.C.,
AND MID CONTINENT MARKET CENTER, INC., CASE NO. 01C0047, IN THE DISTRICT COURT
OF RENO COUNTY, KANSAS. On or about January 22, 2001, two separate class action
lawsuits were filed against ONEOK and several of its affiliates relating to
certain gas explosions in or near Hutchinson, Kansas. The plaintiffs seek to
certify four separate classes of claimants, which include owners of real estate
whose property has declined in value, owners of businesses whose income has
suffered, persons who have been unable to live in their homes for extended
periods of time, and persons who have been unable to work. The petitions seek
recovery on behalf of the class claimants for an amount which will fully and
fairly compensate all members of the class. Discovery as to the appropriateness
of the class is commencing.
26
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.
Name and Position Age Business Experience In Past Five Years
- ------------------------------------------------------------------------------------------------------------------
LARRY W. BRUMMETT (a) 1997 to 2000 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 Executive
and Chief Executive Officer
Officer
- ------------------------------------------------------------------------------------------------------------------
DAVID L. KYLE (b) 48 2000 to present Chairman of the Board of Directors, President, and Chief Executive
Chairman of the 1997 to 2000 Officer
Board, President and 1995 to present President and Chief Operating Officer
Chief Executive 1994 to 1997 Member of the Board of Directors
Officer President and Chief Operating Officer of Oklahoma Natural Gas
Company
- ------------------------------------------------------------------------------------------------------------------
JAMES C. KNEALE 49 2001 to present Senior Vice President, Treasurer, and Chief Financial Officer
Senior Vice (Principal Financial and Accounting Officer)
President, 1999 to 2000 Vice President, Treasurer, and Chief Financial Officer (Principal
Treasurer, and Chief Financial and Accounting Officer)
Financial Officer 1997 to 1999 President and Chief Operating Officer of Oklahoma Natural Gas
(Principal Financial 1996 to 1997 Company
and Accounting 1995 to 1996 Vice President of ONEOK Resources Company
Officer) Vice President - Tulsa District of Oklahoma Natural Gas Company
- ------------------------------------------------------------------------------------------------------------------
JOHN A. GABERINO, JR. 59 1998 to present Senior Vice President and General Counsel
Senior Vice President 1994 to 1998 Stockholder, Officer and Director of Gable & Gotwals
and General Counsel
- ------------------------------------------------------------------------------------------------------------------
JOHN W. GIBSON 48 2000 to present President - Energy ONEOK, Inc.
President - Energy 1996 to 2000 Executive Vice President, Koch Energy, Inc.; President, Koch
Midstream Services; President, Koch Gateway Pipeline Company
1995 to 1996 Senior Vice President, Koch Gateway Pipeline Company
- ------------------------------------------------------------------------------------------------------------------
EUGENE N. DUBAY 52 1997 to present President and Chief Operating Officer of Kansas Gas Service Company
President and Chief 1996 to 1997 Vice President of Corporate Development
Operating Officer of 1994 to 1995 Executive Vice President and Chief Operating Officer of Missouri
Kansas Gas Service Gas Energy
Company
- ------------------------------------------------------------------------------------------------------------------
EDMUND J. FARRELL 57 1999 to present President and Chief Operating Officer of Oklahoma Natural Gas
President and Chief 1997 to 1999 Company
Operating Officer of 1996 to 1997 Vice President of ONEOK Gas Marketing Company
Oklahoma Natural Gas 1995 to 1996 Vice President - Customer Services of Oklahoma Natural Gas Company
Company Vice President - Corporate Communications and Strategic Planning
- ------------------------------------------------------------------------------------------------------------------
BARRY D. EPPERSON (c) 55 1997 to present Vice President, Controller, and Chief Accounting Officer
Vice President, 1994 to 1997 Vice President - Accounting of Oklahoma Natural Gas Company
Controller, and
Chief Accounting
Officer
- ------------------------------------------------------------------------------------------------------------------
(a) Mr. Brummett passed away August 24, 2000.
(b) Mr. Kyle was elected to the position of Chairman of the Board and
appointed Chief Executive Officer of ONEOK, Inc. August 28, 2000.
(c) Mr. Epperson will retire effective April 1, 2001.
27
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 and the transition period were
as follows:
Years Ended
December 31, 2000 August 31, 1999
- -----------------------------------------------------------------------------
High Low High Low
- -----------------------------------------------------------------------------
First Quarter $ 27.56 $ 21.75 $ 37.94 $ 29.94
Second Quarter $ 30.13 $ 24.63 $ 37.19 $ 26.00
Third Quarter $ 39.77 $ 26.31 $ 30.50 $ 24.50
Fourth Quarter $ 50.56 $ 38.50 $ 33.13 $ 29.19
- -----------------------------------------------------------------------------
Transition Period $ - $ - - $ 31.50 $ 25.13
- -----------------------------------------------------------------------------
(B) HOLDERS
There were 14,481 holders of the Company's common stock at March 14, 2001.
(C) DIVIDENDS
Quarterly dividends declared on the Company's common stock during the last two
fiscal years and the transition period were as follows:
Years Ended
December 31, August 31,
2000 1999
- --------------------------------------
First Quarter $ 0.31 $ 0.31
Second Quarter $ 0.31 $ 0.31
Third Quarter $ 0.31 $ 0.31
Fourth Quarter $ 0.31 $ 0.31
- --------------------------------------
Transition Period -- $ 0.31
- --------------------------------------
Debt agreements pursuant to which the Company's outstanding long-term and
short-term debt have been issued limit dividends and other distributions on the
Company's common stock. Under the most restrictive of these provisions, $201.6
million of retained earnings is so restricted. On December 31, 2000, $186.0
million was available for dividends on the Company's common stock.
The Company expects that comparable cash dividends will continue to be paid in
the future.
28
ITEM 6. SELECTED FINANCIAL DATA
Following are selected financial data for the Company for each of the last five
years and the transition period.
Year
Ended Years Ended
December 31, August 31,
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
(Millions of Dollars, except per share amounts)
Operating revenues $ 6,642.9 $ 1,838.9 $ 1,820.8 $ 1,161.6 $ 1,218.6
Operating income $ 333.9 $ 215.7 $ 188.8 $ 127.8 $ 115.0
Net income $ 145.6 $ 106.4 $ 101.8 $ 59.3 $ 52.8
Total assets $ 7,369.1 $ 3,024.9 $ 2,422.5 $ 1,237.4 $ 1,219.9
Long-term debt $ 1,350.7 $ 837.0 $ 329.3 $ 347.1 $ 351.9
Diluted earnings per share $ 2.96 $ 2.06 $ 2.23 $ 2.13 $ 1.93
Dividends per common share $ 1.24 $ 1.24 $ 1.20 $ 1.20 $ 1.18
Percent of payout 41.9% 60.2% 53.8% 56.2% 61.1%
Ratio of earnings to fixed charges 2.88X 4.06x 5.50x 3.51x 3.28x
Ratio of earnings to combined fixed charges
and preferred stock dividend requirements 1.93X 1.93x 2.52x 3.48x 3.24x
- -----------------------------------------------------------------------------------------------------------------------------
Four Months Ended
December 31,
1999 1998
- --------------------------------------------------------------------------------
(Millions of Dollars, except per share amounts)
Operating revenues $ 806.5 $ 580.7
Operating income $ 83.6 $ 68.1
Net income $ 35.3 $ 34.8
Total assets $ 3,241.2 $ 2,557.1
Long-term debt $ 800.7 $ 353.4
Diluted earnings per share $ 0.70 $ 0.67
Dividends per common share $ 0.31 $ 0.31
Percent of payout 44.3% 46.3%
Ratio of earnings to fixed charges 2.98x 4.50x
Ratio of earnings to combined fixed charges
and preferred stock dividend requirements 1.76x 2.02x
- --------------------------------------------------------------------------------
29
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 Form 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
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:
o the effects of weather and other natural phenomena on sales
and prices;
o increased competition from other energy suppliers as well as
alternative forms of energy;
o the capital intensive nature of the Company's business;
o further deregulation, or "unbundling" of the natural gas
business;
o competitive changes in the natural gas gathering,
transportation and storage business resulting from
deregulation, or "unbundling", of the natural gas business;
o the profitability of assets or businesses acquired by the
Company;
o risks of marketing, trading and hedging activities as a result
of changes in energy prices;
o economic climate and growth in the geographic areas in which
the Company does business;
o the uncertainty of gas and oil reserve estimates;
o the timing and extent of changes in commodity prices for
natural gas, natural gas liquids, electricity, and crude oil;
o the effects of changes in governmental policies and regulatory
actions, including income taxes, environmental compliance, and
authorized rates;
o the results of litigation related to the Company's previously
proposed acquisition of Southwest Gas Corporation (Southwest)
or to the termination of the Company's merger agreement with
Southwest; and
o the other factors listed in the reports the Company has filed
and may file with the Securities and Exchange Commission,
which are incorporated by reference.
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.
OPERATING ENVIRONMENT AND OUTLOOK
The energy industry has undergone tremendous changes throughout the past decade.
The Company's strategy has been and continues to be one of growth through
acquiring assets that complement and strengthen each other, maximizing the
earnings potential of existing assets through asset rationalization and
consolidation and introducing regulatory initiatives that benefit the Company
and its customers. The Company believes that the energy markets will continue to
see deregulation, although it may be different than how certain markets have
been deregulated to date. Furthermore, management believes that the natural gas
and electricity markets will continue to converge and consolidate providing
additional opportunities for growth . The Company also believes that demand for
natural gas will increase due in part to the construction of a significant
amount of gas-fired electric generating plants necessary to maintain adequate
supply in the marketplace. As this occurs, we anticipate natural gas prices to
remain strong, although lower than the historic high prices in 2000. With these
changes, Company management also expects to see increased exploration for
natural gas.
30
The Company will continue to focus on enhancing the earnings potential of its
existing assets through acquiring assets that grow the Company's operations into
new market areas and complement its existing asset base. In 2001, the Company
will further develop its trading capabilities by marketing and trading energy
from its 300 megawatt, gas-fired electric generating plant configured to supply
electric power during peak periods.
OPERATING HIGHLIGHTS
ACQUISITIONS AND CAPITAL EXPENDITURES - The Company made two significant asset
acquisitions that greatly enhanced its Gathering and Processing, Transportation
and Storage and Marketing and Trading segments. The combined acquisitions
included natural gas processing plants with a combined capacity of 1.6 Bcf/d,
approximately 19,000 miles of gathering and transmission lines, natural gas
storage facilities with a combined capacity of approximately 10 Bcf and
contributed to a significant increase in trading. The acquisition of these
assets demonstrates execution of the Company's strategy of growing through
acquisition of assets that strengthen and complement each other.
The Company spent approximately $58.7 million in 2000 and approximately $13.5
million in 1999 constructing the $120 million Spring Creek Power Plant expected
to be completed and operational in June 2001. However, if the Company continues
on its existing schedule, the plant may be operational earlier than planned.
The Company's Production segment increased its common ownership interest in
Magnum Hunter Resources, Inc. (MHR) from nine percent to over twenty-one percent
in early 2001. This investment contributed approximately $9.5 million in
earnings during 2000. The growth of MHR through recent successful exploration
and strong natural gas prices is expected to continue contributing to the
Company's earnings.
UNBUNDLING - The Company was subject to several unbundling and regulatory
initiatives during 2000. Some of the more significant actions include removal
from regulation of the Company's gathering and storage assets that were
previously regulated by the OCC. ONG and OGT will be considered as two separate
regulated utilities on a prospective basis. The two utility operations will be
able to function independently in pursuing their respective targets and
objectives. KGS was successful in obtaining approval of weather normalization on
a test basis and obtaining permanent approval of the WeatherProof Bill Program
that had been a temporary program. The Company believes that the successful
implementation of these initiatives and programs will lead to increased
opportunities.
CONSOLIDATED OPERATIONS
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Operating revenues $6,642,858 $1,838,949 $1,820,758
Cost of gas 5,845,726 1,213,478 1,275,119
- ---------------------------------------------------------------------------------------------
Net revenues 797,132 625,471 545,639
Operating costs 319,848 280,045 255,175
Depreciation, depletion, and amortization 143,351 129,704 101,653
- ---------------------------------------------------------------------------------------------
Operating income $ 333,933 $ 215,722 $ 188,811
=============================================================================================
Other income, net $ 18,475 $ 10,500 $ 14,644
=============================================================================================
Cumulative effect of a change in accounting principle $ 3,449 $ -- $ --
Income tax 1,334 -- --
- ---------------------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle,
net of tax $ 2,115 $- $ --
=============================================================================================
31
OPERATING RESULTS - The Company's operating results during 2000 were favorably
impacted by the KMI and Dynegy acquisitions. Greater price volatility in the
U.S. natural gas markets and the Company's ability to successfully execute its
transportation and storage arbitrage strategy, as well as the adoption of
mark-to-market accounting for its trading activities and stronger natural gas
and natural gas liquids prices also contributed to the increase. Operating costs
and depreciation, depletion, and amortization increased primarily due to the KMI
and Dynegy acquisitions. Other income, net includes the $26.7 million gain on
the sale of Indian Basin, and $13.4 million in income from equity investees and
preferred dividends received. This income was partially offset by $13.7 million
of previously deferred transaction and ongoing litigation costs associated with
the terminated acquisition of Southwest Gas Corporation.
Interest expense increased in 2000 compared to 1999 primarily due to increased
debt. Total debt, including notes payable, increased approximately $911.9
million from December 31, 1999 to December 31, 2000. The increase in debt is
primarily due to financing of acquisitions and increased gas costs.
The Company's operations showed gains for 1999 compared to 1998, despite weather
which was warmer than normal. Operating income increased for all segments except
Distribution in fiscal 1999. These increases reflect the effect of additional
gas reserves acquired, additional gathering revenues from acquisitions,
operational changes and efficiencies, general market conditions and an
aggressive marketing campaign by the Company's marketing and trading operation.
TRANSITION PERIOD OPERATING RESULTS
Four Months Ended
December 31,
1999 1998
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Operating revenues $ 806,478 $ 580,701
Cost of gas 587,681 384,682
- -----------------------------------------------------------------------------
Net revenues 218,797 196,019
Operating costs 92,002 86,145
Depreciation, depletion, and amortization 43,227 41,736
- -----------------------------------------------------------------------------
Operating income $ 83,568 $ 68,138
=============================================================================
Other income,net $ 2,396 $ 4,993
=============================================================================
Operating results were strong despite warmer than normal weather. While the four
month periods ended December 31, 1999 and 1998 were both warmer than normal, the
Company used derivative instruments for the 1999/2000 heating season to reduce
the effect of weather variances. During the Transition Period, these derivative
instruments resulted in revenue of $5.7 million, which offset much of the margin
variances caused by weather. This revenue was recorded in the Other segment. The
operations from the assets acquired from Koch also favorably impacted operating
results.
Increased borrowing, primarily due to acquisitions in fiscal 1999, resulted in
increased interest expense for the four months ended December 31, 1999. Gains on
sales of assets of $5.0 million were included in Other Income during the four
month period ended December 31, 1998.
32
MARKETING AND TRADING
OPERATIONAL HIGHLIGHTS - The Company's marketing and trading operation
purchases, stores, markets, and trades natural gas to both the wholesale and
retail sectors in 28 states. The acquisition of KMI's marketing and trading
operation in April 2000 expanded firm transport capacity and storage capacity in
the Mid Continent region. The transport capacity of 1 Bcf/d, allows for trade
from the California border, throughout the Rockies, to the Chicago city gate.
With total storage capacity of 64 Bcf, withdrawal capability of 2.0 Bcf/d and
injection capability of 1.1 Bcf/d, the Company has direct access to all regions
of the country with great flexibility in capturing margins associated with price
volatility in the energy markets.
The acquisition of KMI's marketing and trading operations increased the
Marketing and Trading segment's baseload contracts. However, the Company
continues to enhance its strategy of focusing on higher margin business which
includes providing reliable service during peak demand periods through storage
arbitrage.
Construction of a 300-megawatt electric power plant began in the fourth quarter
of calendar year 1999. The plant is located adjacent to one of the Company's
natural gas storage facilities and will be configured to supply electric power
during peak periods with four gas-powered turbine generators manufactured by
General Electric. Construction of the plant is on schedule with an expected
operational date of June 2001. The construction of this power plant complements
the Company's strategy of maximizing the earnings capacity of existing assets
and exploring new opportunities that are expected to have a positive impact on
earnings.
During 1999, the Company continued to focus on new market areas by arbitraging
storage in the day trading market. Gas volumes increased in 1999 primarily from
the Company's expansion into the Permian/Waha region of the U.S. In 1999, the
Company leased more than 29 Bcf of storage capacity from others and affiliates,
which gives direct access to the west coast and Texas intrastate markets.
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- --------------------------------------------------------------------------------------------------------
FINANCIAL RESULTS (Thousands of Dollars)
Gas sales $4,658,787 $ 821,890 $ 774,455
Cost of gas 4,595,199 789,955 758,687
- --------------------------------------------------------------------------------------------------------
Gross margin on gas sales 63,588 31,935 15,768
Other revenues 2,894 3,508 4,159
- --------------------------------------------------------------------------------------------------------
Net revenues 66,482 35,443 19,927
Operating costs 14,321 9,069 7,024
Depreciation, depletion, and amortization 887 503 561
- --------------------------------------------------------------------------------------------------------
Operating income $ 51,274 $ 25,871 $ 12,342
========================================================================================================
Cumulative effect of a change in accounting principle $ 3,449 $ -- $ --
Income tax 1,334 -- --
- --------------------------------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle, net of tax $ 2,115 $ -- $ --
========================================================================================================
33
OPERATING RESULTS - The increase in Marketing and Trading's gross margins on gas
sales in 2000 compared to 1999, is primarily attributable to the increased
volumes primarily achieved through the acquisition of KMI's marketing and
trading operations. The acquisition significantly increased the segment's
commercial control of storage and transportation positions, primarily in the Mid
Continent, Rocky Mountain and Texas regions, thereby providing more leverage for
its marketing and trading capabilities. Increased price volatility during 2000
compared to 1999, in the U.S. natural gas markets also contributed to increased
gross margin on gas sales by providing greater marketing and trading
opportunities. Gross margin on gas sales was also favorably impacted by the
change in accounting principle requiring the Marketing and Trading segment to
mark energy trading contracts to market.
Increased operating costs in 2000 compared to 1999, is primarily attributable to
increased personnel costs resulting from the KMI acquisition coupled with
increases in overall personnel to support the expanded base of marketing and
trading activities. Operating costs also increased due to higher costs relating
to technological enhancements necessary to support these activities. The
increase in depreciation, depletion and amortization in 2000 compared to 1999,
is a result of increased logistical and risk management systems development
efforts in support of the segment's growth.
The increase in gross margins in 1999 compared to 1998, is attributable to
internal growth primarily driven by increased contracted storage positions.
Seasonal weather trends in 1999 continued to provide price volatility creating
opportunities to capture marketing and trading margin. Increased sales volumes
are primarily due to the expanded niche business into Texas and the west coast.
The increase in operating costs in 1999 compared to 1998, is due to the
additional expenses related to leasing storage and start-up costs for ONEOK
Power Marketing Company. The Company was granted a rate schedule by the FERC to
trade electricity at market-based wholesale rates and has begun trading on a
limited scale.
Year Year Year
Ended Ended Ended
December 31, August 31, August 31,
2000 1999 1998
- -----------------------------------------------------------------------
OPERATING INFORMATION
Natural gas volumes (MMcf) 990,033 389,241 334,364
Gross margin ($/Mcf) $ 0.06 $ 0.08 $ 0.05
Capital expenditures (Thousands) $ 59,512 $ 4,196 $ --
Total assets (Thousands) $3,112,653 $ 273,491 $ 130,100
- -----------------------------------------------------------------------
Marketing and Trading sales volumes averaged 2.7 Bcf/d in 2000 compared with 1.1
Bcf/d in 1999 and 0.9 Bcf/d in 1998. The increase in sales volumes is primarily
due to the KMI acquisition. Gross margin per Mcf decreased in 2000 compared to
1999 as a result of higher baseload sales resulting from the acquisition of
KMI's marketing and trading operation. Through the execution of the Company's
transportation and storage arbitrage strategy, the Company will continue to
focus on capturing higher margin sales.
Capital expenditures for 2000 include $58.7 million for the construction of the
Spring Creek Power Plant. The increase in total assets is primarily attributable
to $1.8 billion in price risk management assets which represent the fair value
of the Company's commodity and derivative trading contracts and storage
inventory and a $1.0 billion increase in accounts receivable due to increased
marketing and trading activities and increased natural gas prices.
34
TRANSITION PERIOD OPERATING RESULTS
Four months ended
December 31,
1999 1998
- ---------------------------------------------------------------------
FINANCIAL RESULTS (Thousands of Dollars)
Gas sales $ 382,650 $ 243,776
Cost of gas 371,556 233,810
- ---------------------------------------------------------------------
Gross margin on gas sales 11,094 9,966
Other revenues 399 2,470
- ---------------------------------------------------------------------
Net revenues 11,493 12,436
Operating costs 3,344 2,730
Depreciation, depletion, and amortization 242 103
- ---------------------------------------------------------------------
Operating income $ 7,907 $ 9,603
=====================================================================
The increase in gross margins is attributable to increased throughput, and a
more extensive use of storage. The use of storage has allowed the Company to
concentrate on the day-to-day market and take advantage of volatility in that
market. Emphasis on base load market had been reduced. Increased sales volumes
are primarily due to the expanded niche business into Texas and the west coast.
The decrease in other revenues is due to the recovery of prior period costs in
the four months ended December 31, 1998. The increase in operating costs is
related to leasing storage and start-up costs for ONEOK Power Marketing Company.
Trading of electricity at market-based wholesale rates had minimal impact on
operations in the Transition Period.
Four months ended
December 31,
1999 1998
- ---------------------------------------------------------------------
OPERATING INFORMATION
Natural gas volumes (MMcf) 138,070 116,309
Gross margin ($/Mcf) $ 0.08 $ 0.08
Capital expenditures (Thousands) $ 13,454 $ 605
Total assets (Thousands) $ 306,705 $ 141,733
- ---------------------------------------------------------------------
The increase in capital expenditures for the Transition Period of 1999 compared
to 1998 is related to the gas-fired electric generating plant the Company began
constructing in 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,
OEMT manages its portfolio of contracts and the Company's assets in order to
maximize value, minimize the associated risks and provide overall liquidity. In
doing so, OEMT uses price risk management instruments, including swaps, options,
futures and physical commodity-based contracts to manage exposures to market
price movements. See Item 7A - Quantitative and Qualitative Disclosures About
Market Risk and Note C in the Notes to Consolidated Financial Statements.
GATHERING AND PROCESSING
OPERATIONAL HIGHLIGHTS - On April 5, 2000, the Company acquired certain natural
gas gathering and processing assets located in Oklahoma, Kansas and West Texas
from KMI. This acquisition includes more than 6,400 miles of pipeline and
natural gas processing plants with a combined capacity of 1.26 Bcf/d. The
current throughput of the assets is approximately 0.76 Bcf/d and production of
NGLs averages 33 MBbls/d.
35
In March 2000, the Company acquired natural gas processing plants with a
combined capacity of 375 MMcf/d and approximately 7,000 miles of gas gathering
pipeline systems in Oklahoma, Kansas and Texas from Dynegy. The current
throughput of the assets is approximately 240 MMcf/d and production of NGLs from
the assets averages 25 MBbls/d.
Year Year Year
Ended Ended Ended
December 31, August 31, August 31,
2000 1999 1998
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Natural gas liquids and condensate sales $536,470 $ 52,757 $ 59,668
Gas sales 426,364 23,032 15,281
Gathering, compression and dehydration revenues 51,734 6,528 --
Processing revenues 15,828 -- --
Cost of Sales 812,701 52,479 53,162
- ----------------------------------------------------------------------------------------
Gross margin 217,695 29,838 21,787
Other revenues 6,317 1,473 3,608
- ----------------------------------------------------------------------------------------
Net revenues 224,012 31,311 25,395
Operating costs 90,501 11,207 7,725
Depreciation, depletion, and amortization 22,692 3,562 2,249
- ----------------------------------------------------------------------------------------
Operating income $110,819 $ 16,542 $ 15,421
========================================================================================
Other income, net $ 26,460 $ -- $ 14,644
========================================================================================
OPERATING RESULTS - Gross margin increased in 2000 compared to 1999 due to the
assets acquired in the KMI and Dynegy acquisitions in early 2000. The increase
in gross margin is also attributable to a full year of operations of the Koch
assets acquired in April 1999. The average NGL price per gallon increased
significantly in 2000 following the rebound in prices for crude oil, which
experienced an upward correction from the abnormally low prices prevalent
throughout much of 1999, which also contributed to increased gross margin.
Gathering, compression and dehydration revenues increased in 2000 compared to
1999 as a result of the assets acquired from KMI and Dynegy. The Company hedged
a portion of their NGL sales during 2000. Since NGL prices were higher than the
hedged price, the Company did not realize the full benefit of higher prices.
However, the Company also hedged a portion of their natural gas costs, which led
to a reduction in natural gas costs since the average market price was higher
than the hedged price. The net effect of these hedges was a reduction in margin
of approximately $22.7 million.
Operating costs and depreciation, depletion and amortization increased as a
result of the assets acquired from KMI and Dynegy acquisitions and the related
goodwill. The increase in operating costs is primarily attributable to increased
personnel and related benefit costs resulting from the additional employees
gained through the KMI and Dynegy acquisitions and additional lease expense
resulting from the Bushton lease. Other income consists of the gain on the sale
of the Company's interest in the Indian Basin processing plant.
Revenues increased in fiscal 1999 due to the acquisition of the midstream assets
from Koch. The average NGL price per gallon for fiscal 1999 was lower than
fiscal 1998. The increase in prices, in late fiscal 1999, corresponded in time
with the increase in volumes from the Koch acquisition. Operating costs and
depreciation, depletion and amortization also increased due to the additional
assets and the cost of operating those assets. At 1999 fiscal year end, total
gas gathered and total gas processed were 688 MMcf /d and 561 MMcf/d, three
times the fiscal 1998 average. This increase in the average per day is due to
the Koch acquisition in April, 1999. Other income in fiscal 1998 consisted of
the gains on sales of assets.
36
Year Year Year
Ended Ended Ended
December 31, August 31, August 31,
2000 1999 1998
- --------------------------------------------------------------------------------
GAS PROCESSING PLANTS OPERATING INFORMATION
Average NGL price realized ($/Gal) $ 0.500 $ 0.263 $ 0.302
Average gas sales price realized ($/Mcf) $ 3.70 $ 2.04 $ 2.30
Total gas gathered (Mcf/D) 1,186,900 229,255 219,971
Total gas processed (Mcf/D) 1,111,400 187,036 198,172
Natural gas liquids sales (MGal) 1,007,343 191,462 194,580
Gas sales (MMcf) 115,180 10,534 5,771
Natural Gas Liquids by Component (%)
Ethane 37 47 42
Propane 32 26 31
Iso butane 5 5 4
Normal butane 12 9 10
Natural gasoline 14 13 13
Contract %
Percent of Proceeds 44 65 54
Keep Whole (a) 32 35 46
Fee 24 -- --
Capital expenditures (Thousands) $ 32,383 $ 8,557 $ 2,235
Total assets (Thousands) $1,507,546 $ 343,133 $ 86,955
- --------------------------------------------------------------------------------
(a) " Keep Whole" amounts were previously reported as "Fuel and Shrink."
The average NGL price realized during 2000 is higher than 1999 primarily due to
the increase in oil prices. Typically, NGL prices follow crude oil prices. The
average gas price realized increased due to the market increase in natural gas
prices. The increase in total gas gathered, gas processed, NGL sales and gas
sales is primarily due to increased processing and fractionation capacity
acquired in the KMI and Dynegy acquisitions in early 2000. Also, the 2000
results include a full year of operations from the Koch acquisition in April
1999.
The increase in capital expenditures is primarily due to the Company
consolidating its plants in Texas to optimize recoveries and lower operating
costs. In addition, the Company had a full year of capital expenditures relating
to the assets acquired from Koch in April 1999 as compared to a partial year of
capital expenditures in 1999. The 1998 fiscal year capital was required to
sustain operations.
The increase in total assets is primarily attributable to a $619.3 million
increase in property, plant and equipment acquired in the KMI and Dynegy
acquisitions and a $99.1 million increase in accounts receivable. The increase
in accounts receivable is due to both increased business and increased prices.
RISK MANAGEMENT - At December 31, 2000, the Gathering and Processing segment
does not have its natural gas costs or NGL production hedged. However, the
Company did use derivative instruments during 2000 to minimize risk associated
with price volatility and expects to utilize such instruments during 2001.
37
TRANSITION PERIOD OPERATING RESULTS
Four Months Ended
December 31,
1999 1998
- -------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Natural gas liquids and condensate sale $ 43,290 $ 8,951
Gas sales 28,824 4,157
Gathering, compression and dehydration rev 6,664 --
Cost of sales 59,488 8,388
- -------------------------------------------------------------------
Gross margin 19,290 4,720
Other revenues 123 1,398
- -------------------------------------------------------------------
Net revenues 19,413 6,118
Operating costs 8,588 2,262
Depreciation, depletion, and amortization 2,513 681
- -------------------------------------------------------------------
Operating income $ 8,312 $ 3,175
===================================================================
Revenues increased in the Transition Period over the same period in 1998 due to
the acquisition of the midstream natural gas gathering and processing assets
from Koch in April, 1999. Operating costs and depreciation also increased due to
the additional assets and the cost of operating those assets. Gathering,
compression, and dehydration revenues result from operation of the Keep Whole
plants acquired from Koch. Average NGL price per gallon increased as prices
continued to experience an upward correction from the abnormally low prices
prevalent throughout much of 1998 and early 1999. Other income in the four
months ended December 31, 1998 consisted of the gains on sales of assets.
Four Months Ended
December 31,
1999 1998
- ----------------------------------------------------------
GAS PROCESSING PLANTS OPERATING INFORMATION
Average NGL price realized ($/Gal) $ 0.371 $ 0.226
Average gas price ($/Mcf) $ 2.71 $ 1.80
Total gas gathered (Mcf/D) 481,183 126,655
Total gas processed (Mcf/D) 396,512 115,141
Natural gas liquids sales (MGal) 126,309 38,934
Gas sales (MMcf) 10,643 2,303
Natural Gas Liquids by Component (%)
Ethane 47 48
Propane 27 25
Iso butane 5 4
Normal butane 9 9
Natural gasoline 12 14
Contract %
Percent of Proceeds 64 65
Keep Whole (a) 36 35
Capital expenditures (Thousands) $ 14,613 $ 974
Total assets (Thousands) $368,904 $ 45,709
- ----------------------------------------------------------
(a) " Keep Whole" amounts were previously reported as "Fuel and Shrink."
38
TRANSPORTATION AND STORAGE
OPERATIONAL HIGHLIGHTS - In early 2000, the Company acquired certain
transmission pipelines and natural gas storage facilities with storage capacity
of approximately 10 Bcf from KMI. The KMI acquisition increased transportation
throughput by an average of 635 MMcf/d and miles of transmission pipeline
approximately 4,733 miles.
During 2000, the Company completed $13.4 million of projects on its storage
facilities. These projects were designed to increase the deliverability and
increase the optionality of certain storage facilities.
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Transportation revenues $ 94,112 $ 78,720 $ 72,744
Storage revenues 38,464 27,763 14,772
Cost of fuel 24,713 4,975 1,948
- ------------------------------------------------------------------------------------
Gross margin on transportation and storage revenues 107,863 101,508 85,568
Gas sales 24,042 -- --
Cost of gas 18,163 -- --
- ------------------------------------------------------------------------------------
Gross margin on gas sales 5,879 -- --
Other revenues 11,840 1,402 3,185
- ------------------------------------------------------------------------------------
Net revenues 125,582 102,910 88,753
Operating costs 44,785 28,919 29,104
Depreciation, depletion, and amortization 18,639 13,852 12,818
- ------------------------------------------------------------------------------------
Operating income $ 62,158 $ 60,139 $ 46,831
====================================================================================
Other income, net $ 3,240 $ 6,495 $ --
====================================================================================
OPERATING RESULTS -Transportation revenues increased due to higher retained fuel
despite reduced tariff rates paid by an affiliate for transportation services.
The increase in retained fuel revenues in 2000, contributed $22.0 million to
transportation revenues. This increase is primarily due to increased
transportation volumes and higher prices. Storage revenues increased during 2000
compared to 1999 due to increased capacity of approximately 10 Bcf resulting
from the acquisition of certain storage facilities from KMI. Although, storage
revenues increased due to the acquisition, overall storage volumes as a percent
of working capacity were down significantly because summer/winter pricing
differentials were not as prominent as in prior years. The cost of sales
increased as a result of the increase in retained fuel revenues.
Gross margin on gas sales relate to merchant gas sales by WesTex that was
acquired in April 2000.
Other revenues include fees for the leasing of the Palo Duro Pipeline to Enogex
and the lease of the Sayre storage facility to NGPL. The increase from 1999 is
primarily related to the leasing fees related to the Palo Duro Pipeline. This
pipeline was acquired from KMI in 2000.
Operating costs and depreciation, depletion, and amortization increased in 2000
compared to 1999 primarily as a result of the KMI acquisition. The increase in
operating expenses is primarily due to increased plant operating and personnel
costs resulting from acquisitions.
Other income, net in 2000 represents income from equity investees. The decrease
from 1999 is due to the prior year number including approximately $5.0 million
of gains on sales of assets.
39
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- -----------------------------------------------------------------
OPERATING INFORMATION
Volumes transported (MMcf) 557,052 348,397 394,801
Working gas in storage (MMcf) 21,566 43,199 46,992
Capital expenditures (Thousands) $ 37,701 $ 32,618 $ 38,271
Total assets (Thousands) $661,894 $373,742 $351,692
- -----------------------------------------------------------------
The increase in volumes transported in 2000 was primarily driven by the
acquisition of certain assets from KMI and Dynegy.
Working gas in storage represents both Company owned and third party gas
available to be withdrawn from the storage facilities and allow the storage
facilities to retain the operating integrity of the storage facility. The
decrease in working gas in storage at December 31, 2000 compared to August 31,
1999, is primarily due to timing. Typically, in the summer months gas is
purchased and injected into storage to be withdrawn in the winter months.
Accordingly, since December 31, 2000 is in the middle of the heating season,
working gas in storage is lower than at August 31, 1999. The Company's storage
levels are currently at approximately 31 percent, which is considerably lower
than the historic five year average of 72.5 percent. The low storage level at
December 31, 2000, is due to the increased demand for natural gas.
Total assets increased due to a $255 million increase in property, plant and
equipment and a $24.6 million increase in accounts receivable, which are
primarily due to the KMI acquisition.
REGULATORY INITIATIVES - In a May 2000 OCC Order, the Company's transportation
assets in Oklahoma included in the Transportation and Storage segment became a
separate regulated utility from the Distribution segment. Pursuant to a July
1999, order by the OCC, the Company's gathering and storage assets and related
services in Oklahoma were removed from utility regulation effective November 1,
1999. Gathering and storage assets, including current gas in storage, of $325.0
million were removed from rate base. The Distribution segment issued bids for
upstream and downstream services in the fall of 1999 with bids awarded in the
spring of 2000. Through the bidding process, the Transportation and Storage
segment maintained 96 percent of the Distribution segment's transportation
services. With unbundling and deregulation of gathering, storage and
transportation services, the Company will be able to compete for business at
market-based rates.
40
TRANSITION PERIOD OPERATING RESULTS
Four Months Ended
December 31,
1999 1998
- -----------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Transportation revenues $24,733 $25,956
Storage revenues 14,171 9,099
Cost of fuel 4,660 2,047
- -----------------------------------------------------------------------
Gross margin on transportation and storage revenues 34,244 33,008
Other revenues 247 942
- -----------------------------------------------------------------------
Net revenues 34,491 33,950
Operating costs 10,184 10,963
Depreciation, depletion, and amortization 5,124 4,554
- -----------------------------------------------------------------------
Operating income $19,183 $18,433
=======================================================================
Other income, net $ 1,074 $ 4,993
=======================================================================
With unbundling and deregulation of gathering and storage service, the Company
is positioned to compete for business at market-based rates. The Company's
strategy to increase its storage utilization through greater injection and
withdrawal capabilities has resulted in increased storage revenues for the
Transition Period compared to the same period in 1998 as well as increased
compressor fuel expense. Decreased transportation rates paid by an affiliate
resulted in decreased transportation revenues for the Transition Period compared
to the same period in 1998.
Four Months Ended
December 31,
1999 1998
- ------------------------------------------------------
OPERATING INFORMATION
Volumes transported (MMcf) 117,055 115,970
Working gas in storage (MMcf) 41,489 49,468
Capital expenditures (Thousands) $ 5,837 $ 13,163
Total assets (Thousands) $437,561 $507,573
- ------------------------------------------------------
DISTRIBUTION
The Distribution segment provides natural gas distribution services in Oklahoma
and Kansas. The Company's operations in Oklahoma are conducted through ONG that
serves residential, commercial, and industrial customers and leases pipeline
capacity. The Company's operations in Kansas are conducted through KGS that
serves residential, commercial, and industrial customers. The Distribution
segment serves about 80 percent of Oklahoma and about 67 percent of Kansas. ONG
is subject to regulatory oversight by the OCC. KGS is subject to regulatory
oversight by the KCC.
OPERATIONAL HIGHLIGHTS - In May 2000, ONG settled a rate case with the OCC that
addressed a number of regulatory and unbundling issues. See the highlights of
this rate case below under "Regulatory Initiatives".
The transaction with Western in the 1998 fiscal year added approximately 660,000
new distribution customers and 1,400 employees. Cost controls were strengthened
throughout the organization. Total employees were reduced through attrition
without compromising customer safety or service.
41
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- --------------------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Gas sales $1,198,604 $ 848,813 $ 883,786
Cost of gas 896,660 530,489 596,375
- --------------------------------------------------------------------------------
Gross margin 301,944 318,324 287,411
PCL and ECT Revenues 59,205 58,037 60,658
Other revenues 16,128 17,100 19,384
- --------------------------------------------------------------------------------
Net revenues 377,277 393,461 367,453
Operating costs 216,629 219,945 197,590
Depreciation, depletion, and amortization 67,717 75,443 66,214
- --------------------------------------------------------------------------------
Operating income $ 97,931 $ 98,073 $ 103,649
================================================================================
OPERATING RESULTS - Gross margin on gas sales decreased in 2000 compared to
fiscal 1999, primarily due to a $15.4 million reduction due to warmer weather in
Kansas during a period in which the Company did not have weather normalization
and reduced tariff rates resulting from unbundling in Oklahoma. The impact of
these decreases on gross margin was partially offset by $12.3 million of gross
margin resulting from additional "As Available Gas Sales" during the year. PCL,
ECT and other revenues have remained flat and are expected to increase slightly
or remain flat due to the increased competition in rates.
The decrease in operating costs in 2000 compared to 1999 has resulted from a
continued successful cost containment program and decreased salary and related
benefit costs resulting from fewer employees. The decrease in depreciation,
depletion, and amortization is the result of the extension of estimated useful
lives for assets located in Oklahoma. The revised estimated lives were approved
by the OCC in a rate order granted in May 2000, which reduced depreciation
expense and revenues by approximately $10.5 million annually for Oklahoma assets
and the transfer of certain transportation assets from the Distribution segment
to the Transportation and Storage segment.
Fiscal 1999 was the first complete year of service to the 660,000 customers
added in the Western acquisition. However, warmer than normal weather,
particularly in Kansas, which was 16 percent warmer than normal and where there
was no temperature normalization, reduced net revenues and more than offset the
effect of having a full twelve months of gas sales volumes and revenues.
Operating costs and depreciation, depletion and amortization increased in fiscal
1999 due to having the acquisition recorded for one full year compared to nine
months for fiscal 1998.
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- ---------------------------------------------------------------
GROSS MARGIN PER MCF
Oklahoma
Residential $ 2.76 $ 3.04 $ 2.99
Commercial $ 1.97 $ 2.47 $ 2.40
Industrial $ 1.09 $ 1.23 $ 1.13
Pipeline capacity leases $ 0.27 $ 0.25 $ 0.24
Kansas
Residential $ 2.44 $ 2.44 $ 2.24
Commercial $ 1.91 $ 1.81 $ 1.75
Industrial $ 1.85 $ 2.28 $ 1.92
End-use customer transportation $ 0.63 $ 0.49 $ 0.56
- ---------------------------------------------------------------
42
The decrease in Oklahoma's gross margin per Mcf for residential, commercial and
industrial customers, in 2000 compared to 1999, is primarily due to decreased
tariff rates resulting from unbundling in Oklahoma. The increase in Kansas'
gross margin per Mcf for commercial customers is largely due to the Company
reducing its minimum capacity requirements for customers to become eligible for
ECT services pursuant to a regulatory order. This resulted in several commercial
customers becoming ECT customers and the remaining commercial customers are low
volume, high margin customers. The decrease in Kansas' industrial gross margin
per Mcf is primarily due to a tariff rate reduction.
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- -----------------------------------------------------------------------
OPERATING INFORMATION
Average Number of Customers
Oklahoma 784,746 748,445 739,684
Kansas 633,698 656,761 652,330
- -----------------------------------------------------------------------
Total 1,418,444 1,405,206 1,392,014
=======================================================================
Capital expenditures (Thousands)
Oklahoma $ 69,013 $ 39,631 $ 41,059
Kansas 55,970 59,054 36,139
- -----------------------------------------------------------------------
Total $ 124,983 $ 98,685 $ 77,198
=======================================================================
Total Assets (Thousands) $2,007,351 $1,722,381 $1,771,999
=======================================================================
Customers per employee
Oklahoma 586 546 475
Kansas 555 510 489
- -----------------------------------------------------------------------
The increase in Oklahoma's number of customers is largely due to the
consolidation of the KGS-Oklahoma regulated service with ONG in 2000. The
related decrease in Kansas' number of customers was partially offset by the
number of customers added with the acquisition of Kansas Gas Supply in the
Dynegy acquisition.
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
capital expenditure program included $21.4 million, $19.8 million and $15.6
million for new business development in 2000, 1999 and 1998, respectively.
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- ---------------------------------------------------------
VOLUMES (MMCF)
Gas sales
Residential 107,154 105,566 103,700
Commercial 40,713 41,398 42,486
Industrial 5,582 5,575 7,304
- ---------------------------------------------------------
Total volumes sold 153,449 152,539 153,490
PCL and ECT 192,881 212,547 241,262
- ---------------------------------------------------------
Total volumes delivered 346,330 365,086 394,752
=========================================================
43
The decrease in PCL and ECT volumes is primarily due to some customers that use
significant quantities of gas in their manufacturing process suspending
manufacturing operations in late 2000 due to historically high natural gas
prices. In addition, volumes decreased due to warmer than normal temperatures in
early 2000. These decreases were partially offset by the Company reducing its
minimum capacity requirements for customers to become eligible for PCL and ECT
services pursuant to a regulatory order. The reduction of the minimum
requirements allowed more low volume, high margin customers to be added to the
customer base that, in turn, increased the total gross margin per Mcf.
REGULATORY INITIATIVES - A rate case was settled between ONG and the OCC on May
30, 2000 in Oklahoma resolving a number of regulatory and unbundling issues. The
more significant issues resolved include the following. Gas storage and gas
gathering were deregulated and the related investments were removed from the
regulated Oklahoma Distribution segment's rate base. A $57 million annual base
rate reduction, effective with the first billing cycle in June 2000, spread
among all customer classes. The PCL Rider was terminated and the $37.8 million
balance was moved to base rates and included in the revenue reduction, thereby
creating a net annual reduction of approximately $20 million. The Company was
allowed to recover approximately $3.5 million annually from its distribution
customers through a Gathering Rider. The KGS-Oklahoma regulated services were
consolidated with ONG, which allows the KGS-Oklahoma customers to be served
under the ONG rate structure and allows the Company to discontinue separate
regulatory reporting and rate case activity for KGS-Oklahoma. However, the
Company did sustain an annual margin reduction estimated at $2.3 million related
to this change since the previous KGS-Oklahoma rates were generally higher than
the comparable ONG rates that will now apply to these customers. As a provision
of this order, ONG and OGT, included in the Transportation and Storage segment,
will be considered two separate regulated utilities on a prospective basis. The
two utility operations are able to function independently in pursuing their
respective targets and objectives.
During 2000, the KCC issued an Order allowing KGS to recover additional costs of
its gas purchase hedging program established to protect the price paid by
customers for gas purchases. This year's unprecedented market volatility and
natural gas prices prompted this action by the KCC. The KCC also approved KGS's
WeatherProof Bill Program that had been a temporary program while being tested.
This plan allows customers, at their discretion, to fix their monthly payment.
The KCC also granted KGS weather normalization that prevents weather related
revenue fluctuations.
ONG began taking bids for transportation services in the fall of 1999 with bids
awarded in spring 2000 for service beginning on November 1, 2000. As a result of
this competitive bid process, OGT retained approximately 96 percent of ONG's
upstream transportation requirements. As contracts with PCL customers expire,
these contracts may be renewed with the Distribution segment, the Transportation
and Storage segment or nonaffiliated service providers. Consequently, this could
result in reduced revenues in the Distribution segment.
TRANSITION PERIOD OPERATING RESULTS
Four Months Ended
December 31,
1999 1998
- ---------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Gas sales $316,901 $286,317
Cost of gas 209,354 180,795
- ---------------------------------------------------------------
Gross margin 105,875 103,850
PCL and ECT revenues 18,230 19,582
Other revenues 4,093 4,554
- ---------------------------------------------------------------
Net revenues 128,198 127,986
Operating costs 69,455 73,004
Depreciation, depletion, and amortization 24,815 24,603
- ---------------------------------------------------------------
Operating income $ 35,600 $ 32,051
===============================================================
44
Gross margins on gas sales increased primarily due to reduced transportation
costs paid to an affiliate and an increase in volumes sold during the Transition
Period compared to the same period in 1998. A reduction in revenues due to the
gathering and storage assets being removed from rate base, as previously
discussed, offset part of that increase. PCL and ECT revenues and volumes
decreased primarily due to the loss of three customers and the effect of warm
weather including the temporary shut-down of two power plants served by the
Distribution segment. The volume decrease was partially offset by an increase in
rates.
Operating costs decreased due to reductions in labor expense, employee benefits,
and other operating efficiencies. The Distribution segment continues its
strategy of increased operational efficiency while maintaining quality customer
service.
Two rate cases were combined in Oklahoma, eliminating an interim rate case
scheduled for the summer of 1999 and providing for a one-time interim rate
reduction of $5 million that began September 1, 1999 for residential customers
in Oklahoma. The amount of the rate reduction in the Transition Period was $1.6
million.
Four Months Ended
December 31,
1999 1998
- -----------------------------------------------------
GROSS MARGIN PER MCF
Oklahoma
Residential $ 2.88 $ 2.96
Commercial $ 2.48 $ 2.51
Industrial $ 1.16 $ 1.27
Pipeline capacity leases $ 0.25 $ 0.23
Kansas
Residential $ 2.76 $ 2.85
Commercial $ 2.07 $ 1.86
Industrial $ 1.97 $ 2.70
End-use customer transportation $ 0.60 $ 0.48
- -----------------------------------------------------
Four Months Ended
December 31,
1999 1998
- ----------------------------------------------------------
OPERATING INFORMATION
Number of Customers 1,435,647 1,421,280
Capital expenditures (Thousands) $ 34,167 $ 24,636
Total Assets (Thousands) $1,776,273 $1,804,631
Customers per employee 546 527
- ----------------------------------------------------------
Four Months Ended
December 31,
1999 1998
- ----------------------------------------------------
VOLUMES (MMCF)
Gas sales
Residential 31,908 31,244
Commercial 11,415 12,005
Industrial 1,795 1,684
- ----------------------------------------------------
Total volumes sold 45,118 44,933
PCL and ECT 61,696 76,974
- ----------------------------------------------------
Total gas sales, PCL and ECT 106,814 121,907
====================================================
45
Certain costs to be recovered through the rate making process have been recorded
as regulatory assets in accordance with Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71). As the Company continues to unbundle its services, certain of these
assets may no longer meet the criteria for following SFAS 71, and accordingly, a
write-off of regulatory assets and stranded costs may be required. The Company
does not anticipate these costs to be significant.
PRODUCTION
OPERATIONAL HIGHLIGHTS - The Company's strategy is to concentrate ownership of
hydrocarbon reserves in the Mid Continent region 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 a growth strategy through acquisitions and developmental drilling,
the number of wells the Company operates has increased. In its role as operator,
the Company controls operating decisions that impact production volumes and
lifting costs. Based on an industry survey, the Company's production segment is
one of the lowest cost small independent producers in the country. The Company
continues to focus on reducing finding costs.
Consistent with the Company's strategy of acquiring assets that strengthen and
complement each other, the Production segment focuses its efforts on
acquisitions and exploitation activities. During 2000, the Company acquired
approximately $4.8 million in gas and oil properties. The Company also increased
activities relating to its developmental drilling program.
During the second quarter of fiscal 1999, the Company consummated the strategic
alliance with Magnum Hunter Resources (MHR) adding $10 million in producing
properties and becoming an equity owner in MHR at a cost of $50 million. The
Company also closed on two other properties with a purchase price of $53 million
adding reserves located in Oklahoma.
The Company purchased natural gas and oil reserves from OXY USA, Inc. (Oxy) in
fiscal 1998. The reserves are located in Oklahoma and Kansas and include more
than 400 wells. Net production was approximately 30 million cubic feet of gas
per day and 400 barrels of oil per day upon acquisition and includes a gas
sweetening plant. The purchase price was approximately $131 million. Based on
estimated reserves, this transaction almost doubled the Company's oil and gas
reserves, at that time.
A 40 percent equity interest in K. Stewart Petroleum Corp. (K Stewart), 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.
RISK MANAGEMENT - Since the volatility of energy prices has a significant impact
on the profitability of this segment, the Company utilizes commodity derivative
instruments to offset this risk. As of December 31, 2000, approximately 74
percent of anticipated gas production in 2001 has been hedged. See Item 7A -
Quantitative and Qualitative Disclosure about Market Risk.
46
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- -----------------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Natural gas sales $60,966 $58,776 $38,323
Oil sales 8,571 6,169 5,192
Other revenues 818 1,949 367
- -----------------------------------------------------------------------
Net revenues 70,355 66,894 43,882
Operating costs 24,228 19,128 14,312
Depreciation, depletion, and amortization 30,884 34,073 18,872
- -----------------------------------------------------------------------
Operating income $15,243 $13,693 $10,698
=======================================================================
Other income, net $10,619 $ 4,005 $ --
=======================================================================
OPERATING RESULTS - Net revenues increased in 2000 compared to 1999, due to
higher natural gas and oil prices that prevailed throughout the year. The
Company hedged the majority of their production, which limited the Company's
ability to capitalize on the high natural gas prices that prevailed in 2000. The
impact of slightly higher commodity prices realized by the Company on revenues
was partially offset by natural declines in production. The production declines
result from the fact that the majority of the Company's reserves are located in
the Mid Continent region, which are characteristically mature fields.
Operating costs increased in 2000 as compared with 1999 as a result of higher
production taxes. Production taxes are based on volumes sold and market price,
gross of hedging activities. Depreciation, depletion and amortization decreased
in 2000 compared to 1999 due to decreased production and a lower average
depletion rate resulting from low finding costs on current discoveries.
Other income, net primarily represents preferred dividends received and the
Company's pro rata portion of income from investments in MHR and K. Stewart. The
increase from 1999 is due to the Company receiving approximately $9.5 million in
preferred dividends from MHR in 2000 compared with approximately $2.3 million in
1999. In late 2000, the Company exercised their MHR stock warrants and redeemed
one-half of its preferred stock. In January 2001, the Company converted its
remaining MHR preferred stock into common stock. The Company currently has an
approximate 21 percent common equity ownership in MHR and no longer has a
preferred stock ownership.
Increased production from a successful developmental drilling program and
properties acquired during fiscal 1999 are the primary reasons for the increases
in revenue compared to fiscal year 1998. Following an industry wide trend, gas
prices during fiscal year 1999 decreased compared to fiscal 1998. Operating
costs and depreciation, depletion, and amortization also increased in fiscal
1999 compared to fiscal 1998 due to the Company operating and owning an interest
in an increased number of wells. However, the Company, through efforts to
contain costs, reduced production costs per Mcf equivalent to $0.49 in 1999 from
$0.50 in 1998.
47
Year Ended Years Ended
December 31, August 31,
2000 1999 1998
- ------------------------------------------------------------------
OPERATING INFORMATION
Proved reserves
Gas (MMcf) 254,721 254,102 178,047
Oil (MBbls) 4,339 4,197 3,272
Production
Gas (MMcf) 26,746 27,773 16,818
Oil (MBbls) 400 460 330
Average realized price (a)
Gas (MMcf) $ 2.28 $ 2.12 $ 2.21
Oil (MBbls) $ 21.43 $ 13.56 $ 15.70
Capital expenditures (Thousands) $ 34,035 $ 16,046 $ 16,650
Total assets (Thousands) $364,248 $361,806 $282,765
- ------------------------------------------------------------------
(a) The average realized price, above, reflects the impact of hedging
activities.
The Production segment added 33.6 Bcfe of reserves and produced 29.1 Bcfe for
the year ended December 31, 2000. The reserve additions are 14.7 Bcfe proved
developed, 4.6 Bcfe proved behind pipe, 13.8 Bcfe proved undeveloped, and 0.5
Bcfe of upward proved reserve additions and acquisitions.
Capital expenditures primarily related to a limited developmental drilling
program were approximately $32.8 million, $13.7 million, and $15.3 million in
2000, 1999, and 1998, respectively. The increase in capital expenditures in
2000, is primarily due to increased developmental drilling activities in 2000 as
compared to fiscal 1999.
TRANSITION PERIOD OPERATING RESULTS
Four Months Ended
December 31,
1999 1998
- -------------------------------------------------------------
(Thousands of Dollars)
FINANCIAL RESULTS
Natural gas sales $20,789 $15,757
Oil sales 2,613 1,742
Other revenues 69 163
- -------------------------------------------------------------
Net revenues 23,471 17,662
Operating costs 7,245 5,227
Depreciation, depletion, and amortization 9,715 10,292
- -------------------------------------------------------------
Operating income $ 6,511 $ 2,143
=============================================================
Other income, net $ 1,322 $ --
=============================================================
Increased production from a successful developmental drilling program and
properties acquired were the primary reasons for the increases in volumes for
the Transition Period compared to the same period in 1998. Gas and oil prices
for the Transition Period also increased compared to the same period in 1998.
Other income, net reflects dividends earned from the preferred stock investment
in MHR. Operating costs also increased, compared to 1998, due to the Company
operating and owning an interest in an increased number of wells.
48
Four Months Ended
December 31,
1999 1998
- -------------------------------------------------------
OPERATING INFORMATION
Proved reserves
Gas (MMcf) 246,979 165,933
Oil (MBbls) 4,160 3,112
Production
Gas (MMcf) 8,306 7,700
Oil (MBbls) 138 145
Average realized price
Gas (MMcf) $ 2.50 $ 2.03
Oil (MBbls) $ 18.93 $ 12.53
Capital expenditures (Thousands) $ 6,411 $ 4,581
Total assets (Thousands) $352,912 $275,840
- -------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The Company's strategy has been and continues to be growth through acquisitions
that strengthen and complement existing assets. For the foreseeable future, the
Company will continue its growth strategy and its capital expenditures program
to adequately maintain its assets. The Company budgeted capital expenditures for
2001, exclusive of any acquisitions that may be made, of $300.8 million. In the
past three years, the Company has relied primarily on a combination of operating
cash flow and borrowings from a combination of commercial paper issuances, lines
of credit, and various public debt issuances for its liquidity and capital
resource requirements.
The Company expects to continue to use these sources for its liquidity and
capital resource needs on both a short and long-term basis. These sources of
funds are expected to be supplemented in 2001 through the use of funds generated
from the Company's Direct Stock Purchase and Dividend Reinvestment Plan that was
amended and restated in January 2001.
CASH FLOW ANALYSIS
The changes in cash flow used in operating activities primarily reflect changes
in working capital accounts and an increase in assets and liabilities from price
risk management activities. The significant changes in working capital accounts
including accounts receivable, gas in storage, accounts payable and deferred
credits and other liabilities is primarily a result of the acquisitions and the
increase in operations resulting from those acquisitions made during 2000 and
historically higher gas prices. The Company had a trend of generating cash flow
from operating activities. However, due to the timing of collections of
receivables and the other factors discussed above, the Company has had a use of
cash in operating activities during 2000. The increase in price risk management
activities is due to the adoption of EITF 98-10 in 2000.
Operating cash flows for fiscal 1999 as compared to 1998, decreased due to
increased prepayments related to hedging activities, increases in unrecovered
purchased gas cost, increased accounts receivables primarily due to increased
sales and increased regulatory assets.
Cash used in investing activities increased in 2000 due to the acquisition of
KMI and Dynegy. The increase in capital expenditures is related to the
construction of the electric generating plant and recurring capital expenditures
necessary to adequately maintain existing assets.
The increase in cash used in investing activities in fiscal 1999 compared to
1998 is primarily due to the $285 million Koch acquisition.
49
Borrowing of notes payable and the issuance of debt in 2000 led to the increase
in cash provided by financing activities. Funds were borrowed to fund the KMI
and Dynegy acquisitions and for general corporate purposes.
The increase in cash provided by financing activities in fiscal 1999 compared to
1998 is due to the issuance of debt to fund the Koch acquisition, general
corporate purposes, repayment of some short-term debt and refinancing certain
long-term debt.
SHORT TERM - The Board of Directors has authorized up to $1.2 billion of short
and intermediate term financing to be secured as necessary for the operation of
the Company. The Company has an $800 million Revolving Credit Facility with Bank
of America, N.A. and other financial institutions with a maturity date of June
30, 2001. In December 2000, the Company arranged for an additional $100 million
Revolving Credit Facility with Bank of America that will expire March 31, 2001.
These credit facilities are primarily used as a commercial paper back up and
replace the previously existing $600 million Revolving Credit Facility dated
July 2, 1999, that matured on June 30, 2000 and the $200 million Revolving
Credit Facility entered into in March 2000 that was terminated on June 1, 2000.
At December 31, 2000, $824 million of commercial paper was outstanding. Based on
the $1.2 billion of financing authorized by the Board of Directors, the Company
could borrow an additional $376 million. Under the terms of the Revolving Credit
Facilities, the Company could borrow an additional $76 million.
LONG-TERM - At December 31, 2000 the Company could have issued approximately
$1.1 billion in additional long-term debt under the most restrictive provisions
contained in various borrowing agreements.
The Company has access to $460 million in equity or debt securities under a
shelf registration filed in May 2000. The Company also has the ability to issue
$300 million in trust preferred securities under a filing made in July 1999.
LIQUIDITY
The Distribution segment continues to face competitive pressure to serve the
transportation market. The loss of a substantial portion of that load due to
third party bypass, 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
SOUTHWEST LITIGATION - In connection with the now terminated proposed
acquisition of Southwest, the Company is party to various lawsuits. The Company
and certain of its officers as well as Southwest and certain of its officers and
others have been named as defendants in a lawsuit brought by Southern Union
Company (Southern Union). The Southern Union allegations include, but are not
limited to, Racketeer, Influenced and Corrupt Organizations Act violations and
improper interference in a contractual relationship between Southwest and
Southern Union. The complaint asks for $750 million damages to be trebled for
racketeering and unlawful violations, compensatory damages of not less than $750
million and rescission of the Confidentiality and Standstill Agreement.
The Company, as third party beneficiary, has filed a lawsuit against Southern
Union for, among other things, breach of a confidentiality agreement with
Southern Union and Southwest and tortuous interference with the Southwest Gas
merger agreement. The Company filed suit against Southwest seeking a declaratory
judgment determining that it had properly terminated the merger agreement. In
response to this suit, Southwest brought a suit against the Company and Southern
Union alleging, among other things, fraud and breach of contract. Southwest is
seeking damages in excess of $75,000.
50
Two substantially identical derivative actions were filed by shareholders
against the members of the Board of Directors of the Company for alleged
violation of their fiduciary duties to the Company by causing or allowing the
Company to engage in certain fraudulent and improper schemes relating to the
planned merger with Southwest and waste of corporate assets. These two cases
were consolidated into one case. Such conduct allegedly caused the Company to be
sued by both Southwest and Southern Union which exposed the Company to million
of dollars of potential liabilities. The plaintiffs seek an award of
compensatory and punitive damages and costs, disbursements and reasonable
attorney fees. The Company and its Independent Directors and officers, named as
defendants, filed Motions to Dismiss the actions for failures of the plaintiffs
to make a pre-suit demand on ONEOK's Board of Directors. Additionally, the
Independent Directors and certain officers named as defendants, filed Motions to
Dismiss the actions for failure to state a claim.
If any of the plaintiffs should be successful in any of their claims against the
Company and substantial damages are awarded, it could have a material adverse
effect on the Company's operations, cash flow, and financial position. The
Company is defending itself vigorously against all claims asserted by Southern
Union and Southwest and all other matters relating to the now terminated merger
with Southwest. For more information, see Legal Proceedings.
HUTCHINSON LITIGATION - Two separate class action lawsuits have been filed
against the Company in connection with the natural gas explosions and eruptions
of natural gas geysers that occurred in Hutchinson, Kansas in January 2001.
Although no assurances can be given, management believes that the ultimate
resolution of these matters will not have a material adverse effect on its
financial position or results of operations. The Company is vigorously defending
itself against all claims. For more information, see Legal Proceedings.
ENVIRONMENTAL - The Company has 12 manufactured gas sites located in Kansas,
which may contain 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 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. Through December
31, 2000, the costs of the investigations and risk analysis related to these
manufactured gas sites have been immaterial. Limited information is available
about the sites and no testing has been performed. Management's best estimate of
the cost of remediation ranges from $100,000 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
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 remediation done and number of years over which
the remediation is completed.
NEW ACCOUNTING PRONOUNCEMENTS - Statement of Financial Accounting Standards No.
133, Accounting for Derivative Instruments and Hedging Activities (Statement
133), was issued by the Financial Accounting Standards Board (FASB) in June,
1998. Statement 133 standardizes the accounting for derivative instruments,
including certain derivative instruments embedded in other contracts. Under
Statement 133, entities are required to record 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.
51
Statement 133 was amended by Statement of Financial Accounting Standards No.
137, Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133, in June 1999 that delayed
implementation until fiscal years beginning after June 15, 2000. Statement 133
was amended again by Statement of Financial Accounting Standards No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities
(Statement 138) in June 2000 that amends the accounting and reporting standards
of Statement 133 for certain derivative instruments and certain hedging
activities. Statement 138 also amends Statement 133 for decisions made by the
FASB relating to the Derivatives Implementation Group (DIG) process. The FASB
DIG is addressing Statement 133 implementation issues the ultimate resolution of
which may impact the application of SFAS 133.
Management has determined that on January 1, 2001, the Company will record a
cumulative effect charge of $2.6 million, net of tax, in the income statement
and $22.9 million, net of tax, in accumulated other comprehensive losses to
recognize at fair value the effective and ineffective portions of the losses on
all derivative instruments that are designated as cash flow hedging instruments,
which primarily consist of costless option collars and swaps on natural gas
production. The Company has no derivative instruments designated as fair value
hedging instruments or other derivative instruments not previously recognized at
January 1, 2001.
The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities - a replacement of FASB
Statement No. 125" (SFAS 140), in September 2000. SFAS 140 revises the standards
for accounting for securitizations and other transfers of financial assets and
collateral and requires certain disclosures. This statement is effective for
transfers and servicing of financial assets and extinguishments of liabilities
occurring after March 31, 2001. SFAS 140 is effective for recognition and
reclassification of collateral and for disclosures relating to securitization
transactions and collateral for fiscal years ending after December 15, 2000. The
adoption of SFAS 140 is not expected to have a material effect on the Company's
financial position or results of operations.
52
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
RISK MANAGEMENT - The Company, substantially through its nonutility segments, is
exposed to market risk in the normal course of its business operations and to
the impact of market fluctuations in the price of natural gas, NGLs and crude
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 and trading operation, and anticipated sales of natural gas and oil
production. To a lesser 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, NGLs and crude oil, the Company uses commodity derivative instruments such
as futures contracts, swaps and options to manage market risk of existing or
anticipated purchase and sale agreements, existing physical gas in storage, and
basis risk. The Company adheres to policies and procedures that limit its
exposure to market risk from open positions and monitors its exposure to market
risk.
To minimize the impact of weather on the Distribution segment's operations, the
Company has used weather derivative swaps to manage the risk of fluctuations in
heating degree days (HDD) during the heating season. Under the weather
derivative swap agreements, the Company receives a fixed payment per degree day
below the contracted normal HDD and pays a fixed amount per degree day above the
contracted normal HDD. The swaps contain a contract cap that limits the amount
either party is required to pay. At December 31, 2000, the Company is not a
party to any weather derivative swaps.
In the past, Kansas Gas Service used derivative instruments to hedge the cost of
some anticipated gas purchases during the winter heating months to protect their
customers from upward volatility in the market price of natural gas. At December
31, 2000, KGS did not have any derivative instruments in place to hedge the cost
of gas purchases.
INTEREST RATE RISK - The Company is subject to the risk of fluctuation in
interest rates in the normal course of business. The Company manages interest
rate risk through the use of fixed rate debt, floating rate debt and interest
rate swaps. In the fourth quarter, the Company unwound its interest rate swap.
Accordingly, the Company had no interest rate swaps at December 31, 2000. At
December 31, 2000 a hypothetical 10 percent change in interest rates would
result in an annual $1.8 million change in interest costs related to short-term
and floating rate debt based on principal balances outstanding at these dates.
VALUE-AT-RISK DISCLOSURE OF MARKET RISK - ONEOK measures entity-wide market risk
in its trading, price risk management, and its non-trading portfolios using
value-at-risk. The quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and products with
different risk factors in order to set overall risk tolerance, to determine risk
targets and set position limits. The use of this methodology requires a number
of key assumptions including the selection of a confidence level and the holding
period to liquidation. ONEOK relies on value-at-risk to determine the potential
reduction in the trading and price risk management portfolio values arising from
changes in market conditions over a defined period.
ONEOK's value-at-risk exposure represents an estimate of potential losses that
would be recognized for its trading and price risk management portfolio of
derivative financial instruments, physical contracts and gas in storage assuming
hypothetical movements in commodity market assumptions with no change in
positions and are not necessarily indicative of actual results that may occur.
Value-at-risk 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 commodity prices, operating exposures
and timing thereof, and the changes in the Company's trading and price risk
management portfolio of derivative financial instruments and physical contracts.
At December 31, 2000, the Company's estimated potential one-day favorable or
unfavorable impact on future earnings, as measured by the value-at-risk, using a
95 percent confidence level and diversified correlation assuming one day to
liquidate positions was $7.3 million for its trading portfolio and $4.4million
for its non-trading portfolio.
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 December 31, 2000, December 31, 1999 and August 31, 1999, and
the related consolidated statements of income, shareholders' equity, and cash
flows for the year ended December 31, 2000, the years ended August 31, 1999 and
1998, and the four months ended December 31, 1999. 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 auditing standards generally accepted
in the United States of America. 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 December 31, 2000, December 31, 1999, and August 31, 1999,
and the results of their operations and their cash flows for the year ended
December 31, 2000, the years ended August 31, 1999 and 1998, and the four months
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note A to the Consolidated Financial Statements, the Company
adopted the provisions of Emerging Issues Task Force 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, in 2000.
KPMG LLP
Tulsa, Oklahoma
February 7, 2001
54
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share amounts)
OPERATING REVENUES (NOTE A) $6,642,858 $ 806,478 $1,838,949 $1,820,758
Cost of gas 5,845,726 587,681 1,213,478 1,275,119
- --------------------------------------------------------------------------------------------------
Net Revenues 797,132 218,797 625,471 545,639
- --------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations and maintenance 266,545 77,247 240,330 221,958
Depreciation, depletion, and amortization 143,351 43,227 129,704 101,653
General taxes 53,303 14,755 39,715 33,217
- --------------------------------------------------------------------------------------------------
Total Operating Expenses 463,199 135,229 409,749 356,828
- --------------------------------------------------------------------------------------------------
Operating Income 333,933 83,568 215,722 188,811
- --------------------------------------------------------------------------------------------------
Other income, net 18,475 2,396 10,500 14,644
Interest expense 118,630 27,883 52,809 35,075
Income taxes 90,286 22,737 67,056 66,585
- --------------------------------------------------------------------------------------------------
Income before cumulative effect of a change in 143,492 35,344 106,357 101,795
accounting principle
Cumulative effect of a change in 2,115 -- -- --
accounting principle, net of tax (Note A)
- --------------------------------------------------------------------------------------------------
NET INCOME 145,607 35,344 106,357 101,795
Preferred stock dividends 37,100 12,367 37,247 26,979
- --------------------------------------------------------------------------------------------------
Income Available for Common Stock $ 108,507 $ 22,977 $ 69,110 $ 74,816
==================================================================================================
Earnings Per Share of Common Stock (Note P)
Basic $ 3.71 $ 0.76 $ 2.19 $ 2.44
==================================================================================================
Diluted $ 2.96 $ 0.70 $ 2.06 $ 2.23
==================================================================================================
Average Shares of Common Stock (Thousands)
Basic 29,224 30,425 31,498 30,674
Diluted 49,194 50,384 51,571 45,729
See accompanying Notes to Consolidated Financial Statements.
55
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, December 31, August 31,
2000 1999 1999
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 249 $ 72 $ 4,402
Trade accounts and notes receivable 1,627,714 371,313 228,336
Materials and supplies 18,119 10,360 10,792
Gas in storage 57,800 124,511 108,159
Deferred income taxes 10,425 8,383 9,702
Purchased gas cost adjustment 1,578 8,105 4,552
Assets from price risk management activities (Note A) 1,416,368 -- --
Customer deposits 120,800 40,928 56,062
Other current assets 71,906 31,714 17,262
- ----------------------------------------------------------------------------------------------
Total Current Assets 3,324,959 595,386 439,267
- ----------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Marketing and Trading 78,686 19,240 5,786
Gathering and processing 1,000,708 385,260 358,439
Transportation and Storage 773,797 526,537 483,983
Distribution 1,860,181 1,766,057 1,771,400
Production 428,701 405,298 399,613
Other 64,056 41,301 38,405
- ----------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 4,206,129 3,143,693 3,057,626
Accumulated depreciation, depletion, and amortization 1,110,616 1,021,915 988,797
- ----------------------------------------------------------------------------------------------
Net Property 3,095,513 2,121,778 2,068,829
- ----------------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets, net (Note D) 238,605 247,486 246,658
Goodwill 93,409 80,743 81,560
Assets from price risk management activities (Note A) 405,666 -- --
Investments and other 210,984 195,847 188,631
- ----------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 948,664 524,076 516,849
- ----------------------------------------------------------------------------------------------
Total Assets $7,369,136 $3,241,240 $3,024,945
==============================================================================================
See accompanying Notes to Consolidated Financial Statements.
56
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, December 31, August 31,
2000 1999 1999
- ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 10,767 $ 21,767 $ 22,817
Notes payable 824,106 462,242 263,747
Accounts payable 1,256,310 237,653 183,759
Accrued taxes 8,735 359 11,186
Accrued interest 24,161 16,628 7,042
Customers' deposits 18,319 18,212 17,139
Liabilities from price risk management activities (Note A ) 1,296,041 -- --
Other 96,913 29,852 37,892
- ------------------------------------------------------------------------------------------------------------
Total Current Liabilities 3,535,352 786,713 543,582
- ------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT, EXCLUDING CURRENT MATURITIES 1,336,082 775,074 810,087
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 382,363 349,883 323,624
Liabilities from price risk management activities (Note A) 543,278 -- --
Lease obligation 137,131 -- --
Other deferred credits 209,973 178,046 173,193
- ------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,272,745 527,929 496,817
- ------------------------------------------------------------------------------------------------------------
Total Liabilities 6,144,179 2,089,716 1,850,486
- ------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTE J)
SHAREHOLDERS' EQUITY
Convertible Preferred Stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and
outstanding 19,946,448 shares at December 31, 2000,
December 31, 1999, and August 31, 1999 199 199 199
Common stock, $0.01 par value:
authorized 100,000,000 shares;issued 31,599,305 shares
and outstanding 29,588,275 shares at December 31, 2000;
issued 31,599,305 shares and outstanding 29,554,623
shares at December 31, 1999; issued 31,599,305 shares
and outstanding 30,844,225 shar316at August 31,31699 316 316 316
Paid in capital (Note F) 895,668 894,976 894,978
Unearned compensation (1,128) (1,846) --
Retained earnings 387,789 317,985 301,536
Treasury stock at cost: 2,011,030 shares at December 31, 2000;
2,044,682 shares at December 31, 1999 and 715,080 shares
at August 31, 1999 (57,887) (60,106) (22,570)
- ------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,224,957 1,151,524 1,174,459
- ------------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 7,369,136 $ 3,241,240 $ 3,024,945
============================================================================================================
57
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
- ----------------------------------------------------------------------------------------------------------------------------
2000 1999 1999 1998
(Thousands of Dollars)
OPERATING ACTIVITIES
Net income $ 145,607 $ 35,344 $ 106,357 $ 101,795
Depreciation, depletion, and amortization 143,351 43,227 129,704 101,653
Gain on sale of assets (27,050) -- (6,639) (14,644)
Net income from equity investments (4,025) (1,063) (1,560) --
Deferred income taxes 26,143 28,317 14,925 (7,623)
Price risk management activities (64,574) -- -- --
Amortization of restricted stock 632 108 -- --
Other 692 -- 293 (2,401)
Changes in assets and liabilities
(Increase) decrease in accounts and notes receivable (1,256,401) (142,977) (50,687) 53,400
(Increase) decrease in inventories (41,669) (15,920) 19,429 1,232
(Increase) decrease in other assets (106,193) (5,457) (88,930) 13,472
Increase in regulatory assets (6,303) (3,841) (6,261) --
(Increase) decrease in purchased gas cost adjustment 6,527 (3,553) (16,720) 54,257
Increase in accounts payable and accrued liabilities 1,009,517 61,928 41,320 51,957
Increase (decrease) in deferred credits and other liabilities 78,559 (1,812) (7,034) (6,396)
- ----------------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Operating Activities (95,187) (5,699) 134,197 346,702
- ----------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Changes in other investments, net 68 994 (59,422) (3,778)
Acquisitions (494,904) (17,482) (344,494) (185,049)
Capital expenditures (311,403) (76,016) (164,170) (140,887)
Proceeds from sale of property 60,659 -- 16,500 30,000
- ----------------------------------------------------------------------------------------------------------------------------
Cash Used in Investing Activities (745,580) (92,504) (551,586) (299,714)
- ----------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Borrowing of notes payable, net 361,864 198,495 51,747 5,302
Issuance of debt 590,000 -- 695,888 --
Payment of debt (39,992) (36,952) (224,868) (17,859)
Issuance of common stock -- -- 1,087 6,081
Acquisition of treasury stock, net (453) (39,610) (22,570) --
Dividends paid (70,475) (28,060) (76,281) (54,803)
Acquisition and cancellation of preferred stock -- -- (3,298) --
- ----------------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Financing Activities 840,944 93,873 421,705 (61,279)
- ----------------------------------------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents 177 (4,330) 4,316 (14,291)
Cash and Cash Equivalents at Beginning of Period 72 4,402 86 14,377
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 249 $ 72 $ 4,402 $ 86
============================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
58
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Unarned
Preferred Common Paid-in Compen- Retained Treasury
Stock Stock Capital sation Earnings Stock Total
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
AUGUST 31, 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 Series A and
Series B, respectively -- -- -- -- (26,979) -- (26,979)
Issuance of Series A and Series B
Convertible Preferred Stock 200 -- 568,122 -- -- -- 568,322
Common stock dividends -
$1.20 per share -- -- -- -- (36,831) -- (36,831)
- ----------------------------------------------------------------------------------------------------------------------------------
AUGUST 31, 1998 200 316 897,547 -- 270,808 -- 1,168,871
Net income -- -- -- -- 106,357 -- 106,357
Issuance of common stock
Stock Purchase Plans -- -- 1,380 -- -- -- 1,380
Convertible preferred stock
dividends - $1.86 and $1.55
per share for Series A and
Series B, respectively -- -- -- -- (37,247) -- (37,247)
Acquisition and Cancellation of
Series B Convertible
Preferred Stock (1) -- (3,949) -- 652 -- (3,298)
Acquisition of Treasury Stock -- -- -- -- -- (22,570) (22,570)
Common stock dividends -
$1.24 per share -- -- -- -- (39,034) -- (39,034)
- ----------------------------------------------------------------------------------------------------------------------------------
AUGUST 31, 1999 $ 199 $ 316 $ 894,978 $-- $ 301,536 $ (22,570) $ 1,174,459
==================================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
59
ONEOK, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Preferred Common Paid-in Unearned Retained Treasury
Stock Stock Capital Compensation Earnings Stock Total
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
AUGUST 31, 1999 199 316 894,978 -- 301,536 (22,570) 1,174,459
Net income -- -- -- -- 35,344 -- 35,344
Issuance of treasury stock -- -- (2) -- (131) 141 8
Convertible preferred stock
dividends - $.465 per share
for Series A -- -- -- -- (9,275) -- (9,275)
Acquisition of treasury stock -- -- -- -- -- (39,610) (39,610)
Issuance of restricted stock -- -- -- (1,933) -- 1,933 --
Amortization of restricted stock -- -- -- 108 -- -- 108
Common stock dividends -
$0.31 per share -- -- -- (21) (9,489) -- (9,510)
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999 199 316 894,976 (1,846) 317,985 (60,106) 1,151,524
Net income -- -- -- -- 145,607 -- 145,607
Issuance of treasury stock -- -- -- -- (2,572) 14,196 11,624
Issuance of common stock
Stock purchase plans -- -- 692 -- -- -- 692
Convertible preferred stock
dividends - $1.86 per share
for Series A -- -- -- -- (37,100) -- (37,100)
Acquisition of treasury stock -- -- -- -- -- (11,812) (11,812)
Issuance of restricted stock -- -- -- (137) -- 137 --
Amortization of restricted stock -- -- -- 632 -- -- 632
Forfeitures of restricted stock -- -- -- 302 -- (302) --
Common stock dividends -
$1.24 per share -- -- -- (79) (36,131) -- (36,210)
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000 $ 199 $ 316 $ 895,668 $ (1,128) $ 387,789 $ (57,887) $1,224,957
=================================================================================================================================
60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS - ONEOK, Inc. and subsidiaries (collectively, the "Company"
or "ONEOK") is a diversified energy company engaged in the production,
processing, gathering, storage, transportation, distribution, and marketing of
natural gas, electricity and natural gas liquids. The Company manages its
business in six segments: Marketing and Trading, Gathering and Processing,
Transportation and Storage, Distribution, Production, and Other.
The Marketing and Trading segment purchases and markets natural gas, primarily
in the Mid Continent region of the United States, and began trading electricity
on a limited basis in 1999. The Company owns and operates gas processing plants
as well as gathering pipelines in Oklahoma, Kansas and Texas through its
Gathering and Processing segment. The Transportation and Storage segment owns
and leases natural gas storage facilities and transports gas in Oklahoma, Kansas
and Texas. The Company's Distribution segment provides natural gas distribution
services in Oklahoma and Kansas through its divisions Oklahoma Natural Gas
Company (ONG) and Kansas Gas Service (KGS) Company. The Production segment
produces natural gas and oil and owns natural gas and oil reserves. 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.
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.
INVENTORIES - Materials and supplies are valued at average cost. Noncurrent gas
in storage is classified as property and is valued at cost. The Marketing and
Trading segment's gas in storage is carried at fair value. Cost of current gas
in storage for ONG is determined under the last-in, first-out, (lifo)
methodology. The estimated replacement cost of current gas in storage valued
under the lifo method was $12.3 million, $7.3 million and $23.1 million at
December 31, 2000 and 1999, and August 31, 1999 respectively, compared to its
value under the lifo method of $4.6 million, $5.7 million and $18.1 million at
December 31, 2000 and 1999,and August 31, 1999, respectively. Current gas in
storage for all other companies is determined using the weighted average cost of
gas method.
ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES- The Company engages in price risk
management activities for both trading and non-trading purposes. On January 1,
2000, the Company adopted Emerging Issues Task Force Issue No. 98-10,
"Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) for
its energy trading contracts. EITF 98-10 requires entities involved in energy
trading activities to account for energy trading contracts using mark-to-market
accounting. Prior to the adoption of EITF 98-10, the Company accounted for its
trading activities on the accrual method based on settlement of physical
positions. The adoption of EITF 98-10 was accounted for as a change in
accounting principle and the cumulative effect at January 1, 2000 of $2.1
million, net of tax, was recognized. Forwards, swaps, options, and energy
transportation and storage contracts utilized for trading activities are
reflected at fair value as assets and liabilities from price risk management
activities in the consolidated balance sheets. The fair value of these assets
and liabilities are affected by the actual timing of settlements related to
these contracts and current period changes resulting primarily from newly
originated transactions and the impact of price movements. Changes in fair value
are recognized in net revenues in the consolidated statement of income. Market
prices used to fair value these assets and liabilities reflect management's best
estimate considering various factors including closing exchange and
over-the-counter quotations, time value and volatility underlying the
commitments. Market prices are adjusted for the potential impact of liquidating
the Company's position in an orderly manner over a reasonable period of time
under present market conditions.
See Note C of Notes to Consolidated Financial Statements.
61
COMMODITY PRICE RISK MANAGEMENT - To minimize the risk from market fluctuations
in the price of natural gas and crude oil, the Company's non-trading segments
enter into futures transactions, swaps, and options in order to hedge natural
gas and crude oil production anticipated sales, fuel requirements and
inventories in its natural gas liquids business to hedge the impact of market
fluctuations. 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 included in the measurement of the subsequent transaction. Energy
contracts held by the Company's non-trading segments are not considered energy
trading contracts under EITF 98-10.
See Note C of Notes to Consolidated Financial Statements.
REGULATED PROPERTY - Regulated properties are stated at cost, which includes an
allowance for funds used during construction. The allowance for funds used
during construction represents the capitalization of the estimated average cost
of borrowed funds (6.9 percent, 6.8 percent, 7.8 percent, and 8.6 percent, in
fiscal year 2000, the four months ended December 31, 1999, and the years ended
August 31, 1999 and 1998, respectively) used during the construction of major
projects and is recorded as a credit to interest expense.
Depreciation is calculated using the straight-line method based upon rates
prescribed for ratemaking purposes. The average depreciation rate for property
that is regulated by the OCC approximated 3.0 percent in fiscal year 2000, 4.1
percent in the four months ended December 31, 1999, and 3.8 and 3.7 percent in
the years ended December 31,1999 and 1998, respectively. The average
depreciation rates for properties regulated by the KCC were approximately 3.3
percent in fiscal year 2000, 3.4 percent in the four months ended December 31,
1999, and 3.2 percent and 3.3 percent in the years ended August 31, 1999 and
1998, respectively. The average depreciation rates for MCMC properties were 3.3
percent in fiscal year 2000, 3.1 percent in the four months ended December 31,
1999, and 3.1 percent and 3.4 percent in the years ended August 31, 1999 and
1998, respectively.
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.
Remaining Service
Life (Years)
- ---------------------------------------------------
Distribution property 22-25 40
Transmission property 18-33 47
Other property 6-24 40
- ---------------------------------------------------
PRODUCTION PROPERTY - The Company uses the successful-efforts method to account
for costs incurred in the acquisition and exploration of natural gas and oil
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 amortized based upon remaining lease terms and
exploratory and developmental drilling experience. Depreciation and depletion
are calculated using the unit-of-production method based upon periodic estimates
of proved oil and gas reserves.
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.
IMPAIRMENTS - The Company accounts for the impairment of long-lived assets to be
recognized when indicators of 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).
62
REGULATION - The intrastate transmission pipelines are subject to the rate
regulation and accounting requirements of the OCC and KCC. The Company's
distribution operations are subject to the rate regulation and accounting
requirements of the OCC and the KCC. Certain other transportation activities of
the Company are subject to regulation by the FERC. ONG and KGS 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
operations. 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.
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 $238.6
million, $247.5 million, and $246.7 million at December 31, 2000 and 1999, and
August 31, 1999, respectively. As the Company continues to unbundle its
services, certain of these assets may no longer meet the criteria for following
SFAS No. 71, and accordingly, a write-off of regulatory assets and stranded
costs may be required. However, the Company does not anticipate that these
costs, if any, will be significant. See Note D of Notes to Consolidated
Financial Statements.
KGS has a two-year rate moratorium. This rate moratorium expires in November
2002. ONG is not subject to a rate moratorium.
GOODWILL - Goodwill, which represents the excess of purchase price over fair
value of net assets acquired, is amortized over a period of 30 to 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. The amount of goodwill impairment, if any, is measured based on
projected discounted future operating cash flows using a discount rate
reflecting the Company's average cost of funds. The assessment of the
recoverability of goodwill will be impacted if estimated future operating cash
flows are not achieved.
ENVIRONMENTAL EXPENDITURES - The Company accrues for losses associated with
environmental remediation obligations when such losses are probable and
reasonably estimable. 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.
REVENUE RECOGNITION - The Company's Marketing and Trading, Gathering and
Processing, Transportation and Storage and Distribution segments recognize
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. ONG's and KGS's tariff rates for
residential and commercial customers contain a temperature normalization clause
that provides for billing adjustments from actual volumes to normalized volumes
during the winter heating season.
Revenues from the Production segment are recognized on the sales 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 operations regulated by
the OCC and for all other operations, is recognized in income in the period that
includes the enactment date. The Company continues to amortize previously
deferred investment tax credits over the period prescribed by the OCC and KCC
for ratemaking purposes.
63
COMMON STOCK OPTIONS AND AWARDS -The Company follows SFAS No. 123, "Accounting
for Stock-Based Compensation" (SFAS 123) which permits, but does not require, a
fair value based method of accounting for stock-based employee compensation.
Alternatively, SFAS 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 123 in Note O of Notes to Consolidated Financial
Statements.
EARNINGS PER COMMON 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.
RECLASSIFICATION - Certain amounts in prior period consolidated financial
statements have been reclassified to conform to the 2000 presentation.
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.
(B) ACQUISITIONS AND DISPOSITIONS
KINDER MORGAN, INC.
On April 5, 2000, the Company acquired certain natural gas gathering and
processing assets located in Oklahoma, Kansas and West Texas from KMI. The
Company also acquired KMI's marketing and trading operations, as well as some
storage and transmission pipelines in the mid-continent region. The Company paid
approximately $109 million for these assets plus working capital of
approximately $53 million, which was subject to adjustment. The working capital
adjustment was made in the first quarter 2001, resulting in the Company
receiving approximately $4.0 million. The Company also assumed certain
liabilities including those related to an operating lease for a processing plant
for which the Company established a liability for an uneconomic lease obligation
and some firm capacity lease obligations to third parties for which the Company
established a reserve for out-of-market terms of those obligations. The
acquisition was accounted for as a purchase. The results of operations of this
acquisition are included in the consolidated statement of income subsequent to
the purchase date.
The table of unaudited pro forma information set forth below, presents a summary
of consolidated results of operations of the Company as if the acquisition of
the businesses acquired from KMI had occurred at the beginning of the periods
presented. The results do not necessarily reflect the results that would have
been obtained if the acquisition had actually occurred on the dates indicated or
the results that may be expected in the future.
Pro Forma
Years Ended
December 31, August 31,
2000 1999
- ----------------------------------------------------------------------
Operating revenues $7,596,667 $5,623,102
Net income $ 153,087 $ 107,271
Income available for common shareholders $ 115,987 $ 70,024
Earnings Per Share of Common Stock - Diluted $ 3.11 $ 2.08
- ----------------------------------------------------------------------
64
In March 2000, the Company completed the sale of its 42.4 percent interest in
Indian Basin Gas Processing Plant and gathering system for $55 million.
In March 2000, the Company completed the acquisition of assets located in
Oklahoma, Kansas, and the Texas panhandle from Dynegy, Inc. for $305 million in
cash, which included a $3 million adjustment for working capital. The assets
include gathering systems, gas processing facilities, and transmission
pipelines.
On January 20, 2000, the Board of Directors of the Company voted unanimously to
terminate the merger agreement with Southwest Gas Corporation (Southwest) in
accordance with the terms of the merger agreement. The Company charged $13.7
million of previously deferred transaction and ongoing litigation costs to Other
income, net for the year ended December 31, 2000. See Note J of Notes to
Consolidated Financial Statements.
(C) PRICE RISK MANAGEMENT ACTIVITIES AND FINANCIAL INSTRUMENTS
Market risks are monitored by a risk control group which operates independently
from the operating segments that create or actively manage these risk exposures.
The risk control group ensures compliance with the Company's risk management
policies.
TRADING ACTIVITIES
The Company's operating results are impacted by commodity price fluctuations.
The Company routinely enters into derivative financial instruments in order to
minimize the risk of commodity price fluctuations related to its purchase and
sale commitments, fuel requirements, transportation and storage contracts and
inventories in its natural gas marketing and trading business.
The Marketing and Trading segment includes the Company's wholesale and retail
natural gas marketing and trading operations. Marketing and Trading generally
attempts to balance its fixed-price physical and financial purchase and sales
commitments in terms of contract volumes and the timing of performance and
delivery obligations. To the extent a net open position exists, fluctuating
commodity market prices can impact the Company's financial position and results
of operations, either favorably or unfavorably. The net open positions are
actively managed and the impact of the changing prices on the Company's
financial condition at a point in time is not necessarily indicative of the
impact of price movements throughout the year.
FAIR VALUE - The fair value and the average fair value of derivative financial
instruments, purchase and sale commitments, fuel requirements, transportation
and storage contracts and inventories related to trading price risk management
activities held during 2000 are set forth as follows:
Fair Value Average Fair Value (a)
December 31, 2000 December 31, 2000
Assets Liabilities Assets Liabilities
- ---------------------------------------------------------------------------
(Thousands of Dollars)
Natural gas commodities $1,822,034 $1,839,319 $1,254,446 $1,394,605
- ---------------------------------------------------------------------------
(a) Computed using the ending balance at the end of each quarter.
The Company did not hold any other commodity type contracts for trading price
risk management purposes at December 31, 2000.
65
NOTIONAL VALUE - The notional contractual quantities associated with trading
price risk management activities are set forth as follows:
Volumes Volumes
Purchased Sold
- ---------------------------------------
(Volumes in MMcf)
DECEMBER 31, 2000
NATURAL GAS OPTIONS 75,320 65,666
NATURAL GAS SWAPS 683,591 733,783
NATURAL GAS FUTURES 114,310 112,740
- ---------------------------------------
Notional amounts reflect the volume and indicated activity of transactions but
do not represent the amounts exchanged by the parties or cash requirements
associated with these financial instruments. Accordingly, notional amounts do
not accurately measure the Company's exposure to market or credit risk.
CREDIT RISK - In conjunction with the market valuation of its energy commodity
contracts, the Company provides reserves for risks associated with its contract
commitments, including credit risk. Credit risk relates to the risk of loss that
the Company would incur as a result of nonperformance by counterparties pursuant
to the terms of their contractual obligations. The Company maintains credit
policies with regard to its counterparties that management believes
significantly minimize overall credit risk. These policies include an evaluation
of potential counterparties' financial condition (including credit ratings),
collateral requirements under certain circumstances and the use of standardized
agreements which allow for netting of positive and negative exposures associated
with a single counterparty.
Counterparties in its trading portfolio consist primarily of financial
institutions, major energy companies, and local distribution companies. This
concentration of counterparties may impact the Company's overall exposure to
credit risk, either positively or negatively in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions. Based
on the Company's policies, its exposures and its credit and other reserves, the
Company does not anticipate a material adverse effect on financial position or
results of operations as a result of counterparty nonperformance. The Company's
credit exposure to California utilities at December 31, 2000, is less than $5
million.
NON-TRADING ACTIVITIES
Financial instruments are also utilized for non-trading purposes to hedge
natural gas and crude oil production anticipated sales, fuel requirements and
inventories in its natural gas liquids business to hedge the impact of market
fluctuations. Interest rate swaps are used to manage interest rate risk. Gains
and losses from hedging transactions are recognized in income and are reflected
as cash flows from operating activities in the periods for which the underlying
commodity or interest rate transactions were hedged. If the necessary
correlation to the commodity or interest rate transaction being hedged is not
maintained, the Company ceases to account for the contract as a hedge and
recognizes a gain or loss in current earnings to the extent the contract results
have not been offset by the effects of the price or interest rate changes on the
hedged item. If the underlying being hedged by the commodity or interest rate is
disposed of or otherwise terminated, the gain or loss associated with such
contract(s) is no longer deferred and is recognized in the period the underlying
is eliminated.
Operating margins associated with the Gathering and Processing segment's natural
gas gathering, processing and fractionation activities are sensitive to changes
in natural gas liquids prices, principally as a result of contractual terms
under which natural gas is processed and products are sold and the availability
of inlet volumes. Also, certain processing plant assets are impacted by changes
in, and the relationship between, natural gas and natural gas liquids prices,
which, in turn influences the volumes of gas processed.
66
FAIR VALUE - The following table represents the estimated fair values of
derivative instruments related to the Company's non-trading price risk
management activities. These instruments have no carrying value.
Approximate
Fair Value
- -----------------------------------------
(Thousands of Dollars)
December 31, 2000
Natural gas commodities $ (41,623)
- -----------------------------------------
August 31, 1999
Natural gas commodities $ (11,540)
- -----------------------------------------
NOTIONAL VALUE - At December 31, 2000, the Company was a party to natural gas
commodity derivative instruments including swaps and options covering 32.9 Bcf
of natural gas for the year 2001.
The Company utilized derivative contracts to mitigate its risk associated with
weather for the month of November 2000 to reduce the impact of degree day
deviations from normal weather. The Company did not have any weather hedges in
place at December 31, 2000.
CREDIT RISK - The Company maintains credit policies with regard to its
counterparties that management believes significantly minimize overall credit
risk. These policies include an evaluation of potential counterparties'
financial condition (including credit ratings), collateral requirements under
certain circumstances and the use of standardized agreements which allow for
netting of positive and negative exposures associated with a single
counterparty.
The counterparties to the non-trading instruments include affiliates and large
integrated energy companies. Accordingly, the Company does not anticipate a
material adverse effect on financial position or results of operations as a
result of counterparty nonperformance.
FINANCIAL INSTRUMENTS
The following table represents the carrying amounts and estimated fair values of
the Company's financial instruments, excluding trading activities, which are
marked to market, and non-trading commodity instruments, which are listed in the
table above.
Approximate
Book Value Fair Value
- -------------------------------------------------------
(Thousands of Dollars)
DECEMBER 31, 2000
CASH AND CASH EQUIVALENTS $ 249 $ 249
ACCOUNTS AND NOTES RECEIVABLE $1,627,714 $1,627,714
NOTES PAYABLE $ 824,106 $ 824,106
LONG-TERM DEBT $1,350,689 $1,302,104
- -------------------------------------------------------
Approximate
Book Value Fair Value
- -------------------------------------------------------
(Thousands of Dollars)
December 31,1999
Cash and cash equivalents $ 72 $ 72
Accounts and notes receivable $ 371,313 $ 371,313
Notes payable $ 462,242 $ 462,242
Long-term debt $ 800,731 $ 753,298
- -------------------------------------------------------
67
Approximate
Book Value Fair Value
- ---------------------------------------------------
(Thousands of Dollars)
August 31, 1999
Cash and cash equivalents $ 4,402 $ 4,402
Accounts and notes receivable $228,336 $228,336
Notes payable $263,747 $263,747
Long-term debt $836,975 $790,961
- ---------------------------------------------------
The fair value of cash and cash equivalents, accounts and notes receivable and
notes payable approximate book value due to their short term nature. The
estimated fair value of long-term debt has been determined using quoted market
prices of the same or similar issues, discounted cash flows, and/or rates
currently available to the Company for debt with similar terms and remaining
maturities.
(D) REGULATORY ASSETS
The table presents a summary of regulatory assets, net of amortization, at
December 31, 2000 and 1999 and August 31, 1999.
December 31, December 31, August 31,
2000 1999 1999
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Recoupable take-or-pay $ 79,324 $ 84,343 $ 85,996
Pension costs 15,306 19,487 20,881
Postretirement costs other than pension 61,069 62,207 61,830
Transition costs 22,199 22,746 22,903
Reacquired debt costs 23,209 24,068 22,413
Income taxes 30,727 23,337 24,114
Other 6,771 11,298 8,521
- ------------------------------------------------------------------------------
Regulatory assets, net $238,605 $247,486 $246,658
==============================================================================
The remaining recovery period for these assets that the Company is not earning a
return on is set forth in the table below.
Remaining Recovery
Period (Months)
- --------------------------------------------------------
Postretirement costs other than
pension - Oklahoma 153
Income taxes - Oklahoma 126-142
Transition costs 443
- --------------------------------------------------------
The OCC directed ONG to assume responsibility for, and ownership of, customer
service lines and has authorized the Company to defer as regulatory assets the
depreciation and operation and maintenance expenses incurred in connection with
this plan. The recovery methodology, amount, and calculation of these deferrals
will be addressed in ONG's next rate case filing. Through December 2000, the
Company has deferred approximately $200,000 associated with this Commission
directive. These deferred costs are included in the caption "Other" in the table
of regulatory assets, above.
The OCC has authorized ONG to defer the incremental costs associated with a
five-year cathodic protection program to be implemented to comply with the OCC's
Pipeline Safety Department inspection reports. The recovery methodology and
amount of these deferred expenses will be addressed in ONG's next rate case
filing. Through December 2000, the Company has deferred approximately $700,000
associated with this program. These deferred costs are included in the caption
"Other" in the table of regulatory assets, above.
68
The OCC has authorized recovery of the take-or-pay settlement, pension and
postretirement benefit costs over a 10 to 20 year period. KGS has been deferring
and recording postretirement benefits in excess of pay-as-you-go as a regulatory
asset as authorized by the KCC. See Note I of Notes to Consolidated Financial
Statements.
The KCC has allowed certain transition costs to be amortized and recovered in
rates over a 40-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.
The Company amortizes reacquired debt costs, which includes unamortized debt
costs, in accordance with the accounting rules prescribed by the OCC and KCC.
These costs have been included in recent rate filings with the OCC and will be
included in future rate filings with the KCC as a component of interest.
In accordance with various rate orders received from the KCC and the OCC, KGS
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.
Amortization expense related to regulatory assets was approximately $10.6
million for the year ended December 31, 2000, $3.1 million for the four months
ended December 31, 1999, and $13.7 million and $11.4 million for the years ended
August 31, 1999 and 1998, respectively.
(E) CAPITAL STOCK
The Company has approximately 42 million shares of unrestricted common stock
available for issue. The Company issued Series A Convertible Preferred Stock,
par value $0.01 per share, at the time of the transaction with Western
Resources, Inc. 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 for the first five years of the agreement. After five
years, the rate will be 1.25 times the dividend amount declared in respect of
each share of common stock, and at no time, will the dividend be less than $1.80
per share.
The terms of Series B Convertible Preferred Stock were the same as Series A
Convertible Preferred Stock, except that the dividend amount was equal to the
greater of 1.25 times the common stock dividend or $1.50 per share. In 1999, the
Company acquired and canceled all of the Series B Convertible Preferred Stock it
had issued in 1998 and 1999.
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 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 Convertible Preferred Stock.
During 1999, the Company initiated a stock buyback plan for up to 15 percent of
its capital stock. The program authorizes the Company to make purchases of its
common stock on the open market with the timing and terms of purchases and the
number of shares purchased to be determined by management based on market
conditions and other factors. Through December 31, 2000, the shares purchased
totaled 2.6 million. The purchased shares are held in treasury and available for
general corporate purposes, funding of stock-based compensation plans, resale at
a future date, or retirement. Purchases are financed with short-term debt or are
made from available funds.
69
The Board of Directors has reserved three million shares of ONEOK, Inc.'s common
stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which
95,000 shares were issued in fiscal year 2000, 28,000 shares were issued in the
four months ended December 31, 1999, and 127,000 and 142,000 shares were issued
in the years ended August 31, 1999 and 1998, respectively. In January 2001, the
Company amended and restated, in entirety, the existing Direct Stock Purchase
and Dividend Reinvestment Plan. The Company reserved three million shares of
ONEOK Inc.'s common stock for this amended and restated plan and may utilize any
shares remaining under the original Direct Stock Purchase and Dividend
Reinvestment Plan, resulting in a total of 5.7 million shares available for this
plan. The Company has reserved approximately 6.6 million shares for the Thrift
Plan for Employees of ONEOK, Inc. and Subsidiaries.
Under the most restrictive covenants of the Company's loan agreements, $186.0
million (48 percent) of retained earnings were available to pay dividends at
December 31, 2000.
(F) PAID IN CAPITAL
Paid in capital was $331.5 million and $330.8 million for common stock at
December 31, 2000 and 1999, respectively. Paid in capital at August 31, 1999,
was $330.8 million for common stock. Paid in capital for convertible preferred
stock was $564.2 million at December 31, 2000 and 1999, and August 31, 1999.
(G) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE
Commercial paper and short-term notes payable totaling $824.1 million, $462.2
million and $263.7 million were outstanding at December 31, 2000 and 1999, and
at August 31, 1999, respectively. The commercial paper and notes carried average
interest rates of 6.53 percent, 6.47 percent, and 5.42 percent at December 31,
2000 and 1999, and August 31, 1999, respectively. The Company has an $800
million and $100 million short-term unsecured revolving credit facilities, which
provide a back-up line of credit for commercial paper in addition to providing
short-term funds. Interest rates and facility fees are based on prevailing
market rates and the Company's credit ratings. No compensating balance
requirements existed at December 31, 2000. Maximum short-term debt from all
sources as approved by the Company's Board of Directors is $1.2 billion.
(H) LONG-TERM DEBT
The aggregate maturities of long-term debt outstanding at December 31, 2000, are
$10.8 million; $250 million; $10 million; $50 million; and $360 million for 2001
through 2005, respectively, including $6 million, which is callable at the
option of the holder in each of those years. All long-term notes payable at
December 31, 2000, are unsecured.
The Company issued $240 million of two-year floating rate notes in April 2000.
The interest rate for these notes resets quarterly at a 0.65 percent spread over
the three month London InterBank Offered Rate (LIBOR). The proceeds from the
notes were used to fund acquisitions. In March 2000, the Company issued $350
million of five year, 7.75 percent, fixed rate notes to refinance short-term
debt and finance acquisitions.
70
December 31, December 31, August 31,
2000 1999 1999
- ------------------------------------------------------------------------
(Thousands of Dollars)
Long-term Notes Payable
6.43% due 2000 $ -- $ 5,000 $ 5,000
7.25% due 2001 767 1,535 1,534
6.403% due 2002 240,000 -- --
8.44% due 2004 40,000 40,000 40,000
7.75% due 2005 350,000 -- --
7.75% due 2006 300,000 300,000 300,000
8.32% due 2007 28,000 32,000 32,000
6.00% due 2009 100,000 100,000 100,000
6.40% due 2019 96,502 99,308 99,794
9.70% due 2019 -- 8,826 8,826
9.75% due 2020 -- 15,305 15,305
8.70% due 2021 -- -- 34,871
6.50% due 2028 95,420 98,757 99,645
6.875% due 2028 100,000 100,000 100,000
- ------------------------------------------------------------------------
Total Long-term Notes Payable 1,350,689 800,731 836,975
Unamortized debt discount 3,840 3,890 4,071
Current maturities 10,767 21,767 22,817
- ------------------------------------------------------------------------
Long-term debt $1,336,082 $ 775,074 $ 810,087
========================================================================
(I) EMPLOYEE BENEFIT 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. The Company generally
funds pension costs at a level equal to the minimum amount required under the
Employee Retirement Income Security Act of 1974.
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) and amortize it over 20 years as a component of net
periodic postretirement benefit cost.
The following tables set forth the Company's pension and other postretirement
benefit plans benefit obligations, fair value of plan assets, and funded status
at December 31, 2000 and 1999, and August 31, 1999.
71
Pension Benefits Postretirement Benefits
December 31, August 31, December 31, August 31,
2000 1999 1999 2000 1999 1999
- --------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of period $ 495,061 $ 504,865 $ 500,327 $ 146,589 $ 160,371 $ 153,326
Service cost 9,365 2,829 9,282 3,566 1,297 4,036
Interest cost 34,806 11,431 32,832 10,312 3,636 10,055
Participant contributions -- -- -- 1,173 334 2,260
Plan amendments -- -- 7,600 (7,816) (10,893) 1,956
Actuarial gain (25,965) (13,973) (15,501) (5,228) (4,786) (4,081)
Benefits paid (31,388) (10,091) (29,675) (12,439) (3,370) (7,181)
- --------------------------------------------------------------------------------------------------------------------------
Benefit obligation, end of period $ 481,879 $ 495,061 $ 504,865 $ 136,157 $ 146,589 $ 160,371
==========================================================================================================================
CHANGE IN PLAN ASSETS
Fair value of assets, beginning of period $ 640,330 $ 660,386 $ 595,308 $ 17,837 $ 17,500 $ 14,075
Actual return on assets 137,791 (10,198) 93,854 1,941 (674) (111)
Employer contributions 902 233 899 4,332 1,011 3,536
Benefits paid (31,388) (10,091) (29,675) -- -- --
- --------------------------------------------------------------------------------------------------------------------------
Fair value of assets, end of period $ 747,635 $ 640,330 $ 660,386 $ 24,110 $ 17,837 $ 17,500
==========================================================================================================================
Funded status - over(under) $ 265,756 $ 145,269 $ 155,521 $(112,048) $(128,752) $(142,871)
Unrecognized net asset (1,715) (2,182) (2,338) -- -- --
Unrecognized transition obligation -- -- -- 24,758 34,332 43,048
Unrecognized prior service cost 6,934 7,756 8,030 -- 877 4,195
Unrecognized net (gain)loss (188,392) (79,969) (93,683) 9,689 16,356 18,379
Activity subsequent to measurement date -- -- -- (793) (998) (1,306)
- --------------------------------------------------------------------------------------------------------------------------
(Accrued)prepaid pension cost $ 82,583 $ 70,874 $ 67,530 $ (78,394) $ (78,185) $ (78,555)
==========================================================================================================================
ACTUARIAL ASSUMPTIONS
Discount rate 7.75% 7.25% 7.00% 7.75% 7.25% 7.00%
Expected rate of return 9.25% 9.25% 9.00% 9.25% 9.25% 8.00%
Compensation increase rate 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
Pension Benefits
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- -------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 9,365 $ 2,829 $ 9,282 $ 7,221
Interest cost 34,806 11,431 32,832 30,875
Expected return on assets (55,566) (17,581) (46,846) (38,686)
Amortization of unrecognized net asset at adoption (467) (156) (467) (467)
Amortization of unrecognized prior service cost 822 274 177 177
Amortization of loss 233 92 786 146
- -------------------------------------------------------------------------------------------------
Net periodic benefit cost $(10,807) $ (3,111) $ (4,236) $ (734)
=================================================================================================
Postretirement Benefits
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- ----------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 3,566 $ 1,297 $ 4,036 $ 2,570
Interest cost 10,312 3,636 10,055 8,224
Expected return on assets (1,792) (616) (1,325) (739)
Amortization of unrecognized net transition obligation
at adoption 2,512 1,025 3,235 3,235
Amortization of unrecognized prior service cost -- 66 -- (212)
Amortization of loss 430 154 688 --
- ----------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 15,028 $ 5,562 $ 16,689 $ 13,078
====================================================================================================
72
For measurement purposes, a 6.65 percent annual rate of increase in the per
capita cost of covered medical benefits (i.e., medical cost trend rate) was
assumed for 2000, 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 December
31, 2000, by $10.1 million and the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for the year ended
December 31, 2000, by $1.5 million. Decreasing the assumed medical cost trend by
one percentage point in each year would decrease the accumulated postretirement
benefit obligation as of December 31, 2000, by $8.5 million and the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for the year ended December 31, 2000, by $1.2 million.
EMPLOYEE THRIFT PLAN - The Company has a Thrift Plan covering substantially all
employees. Employee contributions are discretionary. Subject to certain limits,
employee contributions are matched by the Company. The cost of the plan was $6.7
million in fiscal year 2000; $2.3 million for the four months ended December 31,
1999; and $6.3 million and $4.7 million for the years ended August 31, 1999 and
1998, respectively.
POSTEMPLOYMENT BENEFITS - The Company pays postemployment benefits to former or
inactive employees after employment but before normal retirement.
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 assets regulated by the KCC 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
when the rate moratorium expires and anticipates that recovery will be allowed
over a period not to exceed approximately 10 years. If these costs cannot 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 $52.5 million at
December 31, 2000.
(J) 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. Annual rent expense for the lease will be
approximately $6.8 million until 2009. Rent payments were $9.3 million for
fiscal year 2000, $2.9 million for the four months ended December 31, 1999, and
$5.8 million for the years ended August 31,1999 and 1998. Estimated future
minimum rental payments for the lease are $9.3 million for each of the years
ending December 31, 2001 through 2009.
The Company has the right to sublet excess office space in ONEOK Plaza. The
Company received rental revenue of $3.5 million in fiscal year 2000, $1.0
million for the four months ended December 31, 1999, and $2.8 million for the
years ended August 31,1999 and 1998, for various subleases. Estimated minimum
future rental payments to be received under existing contracts for subleases are
$3.4 million in 2001, $3.1 million in 2002, $2.6 million in 2003, $1.9 million
in 2004, $1.2 million in 2005, and a total of $1.9 million thereafter.
73
Other operating leases include a gas processing plant, office buildings, and
equipment. Future minimum lease payments under noncancelable operating leases
(with initial or remaining lease terms in excess of one year) as of December 31,
2000 are $26.5 million in 2001, $22.1 million in 2002, $16.8 million in 2003,
$21.3 million in 2004 and $24.6 million in 2005. The above amounts include the
following minimum lease payments relating to the lease of a gas processing
plant: $25.5 million in 2001, $21.3 million in 2002, $16.2 million in 2003,
$20.9 million in 2004, and $24.2 million in 2005. The Company has a liability
for uneconomic lease terms relating to the gas processing plant. Accordingly,
the liability is amortized to rent expense in the amount of $13.0 million per
year over the term of the lease.
SOUTHWEST GAS CORPORATION - In connection with the now terminated proposed
acquisition of Southwest, the Company is party to various lawsuits. The Company
and certain of its officers as well as Southwest and certain of its officers and
others have been named as defendants in a lawsuit brought by Southern Union
Company (Southern Union). The Southern Union allegations include, but are not
limited to, Racketeer, Influenced and Corrupt Organizations Act violations and
improper interference in a contractual relationship between Southwest and
Southern Union. The complaint asks for $750 million damages to be trebled for
racketeering and unlawful violations, compensatory damages of not less than $750
million and rescission of the Confidentiality and Standstill Agreement.
The Company, as third party beneficiary, has filed a lawsuit against Southern
Union for, among other things, breach of a confidentiality agreement with
Southern Union and Southwest and tortuous interference with the Southwest Gas
merger agreement. The Company filed suit against Southwest seeking a declaratory
judgment determining that it had properly terminated the merger agreement. In
response to this suit, Southwest brought a suit against the Company and Southern
Union alleging, among other things, fraud and breach of contract. Southwest is
seeking damages in excess of $75,000.
Two substantially identical derivative actions were filed by shareholders
against the members of the Board of Directors of the Company for alleged
violation of their fiduciary duties to the Company by causing or allowing the
Company to engage in certain fraudulent and improper schemes relating to the
planned merger with Southwest and waste of corporate assets. These two cases
were consolidated into one case. Such conduct allegedly caused the Company to be
sued by both Southwest and Southern Union which exposed the Company to million
of dollars of potential liabilities. The plaintiffs seek an award of
compensatory and punitive damages and costs, disbursements and reasonable
attorney fees. The Company and its Independent Directors and officers, named as
defendants, filed Motions to Dismiss the actions for failures of the plaintiffs
to make a pre-suit demand on ONEOK's Board of Directors. Additionally, the
Independent Directors and certain officers named as defendants, filed Motions to
Dismiss the actions for failure to state a claim.
If any of the plaintiffs should be successful in any of their claims against the
Company and substantial damages are awarded, it could have a material adverse
effect on the Company's operations, cash flow, and financial position. The
Company is defending itself vigorously against all claims asserted by Southern
and Southwest and all other matters relating to the now terminated merger with
Southwest.
ENVIRONMENTAL - The Company has responsibility for 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 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 December 31, 2000, the costs of the investigations
and risk analysis have been immaterial. 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.
74
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
of such matters will not have a materially adverse effect on consolidated
results of operations, financial position, or liquidity.
(K) INCOME TAXES
The provisions for income taxes are as follows:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
- -------------------------------------------------------------------------------------
2000 1999 1999 1998
(Thousands of Dollars)
Current income taxes
Federal $55,764 $ (6,345) $48,760 $ 62,462
State 8,379 765 3,371 11,746
- -------------------------------------------------------------------------------------
Total current income taxes 64,143 (5,580) 52,131 74,208
- -------------------------------------------------------------------------------------
Deferred income taxes
Federal 23,947 25,938 13,671 (6,325)
State 2,196 2,379 1,254 (1,298)
- -------------------------------------------------------------------------------------
Total deferred income taxes 26,143 28,317 14,925 (7,623)
- -------------------------------------------------------------------------------------
Total provision for income taxes $90,286 $ 22,737 $67,056 $ 66,585
=====================================================================================
Following is a reconciliation of the provision for income taxes.
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
- ----------------------------------------------------------------------------------------------------------------
2000 1999 1999 1998
(Thousands of Dollars)
Pretax income $ 233,778 $ 58,081 $ 173,413 $ 168,380
Federal statutory income tax rate 35% 35% 35% 35%
- ----------------------------------------------------------------------------------------------------------------
Provision for federal income taxes 81,822 20,328 60,695 58,933
Amortization of distribution property investment tax credit (807) (302) (1,103) (938)
State income taxes, net of federal tax benefit 6,874 2,044 5,737 6,253
Other, net 2,397 667 1,727 2,337
- ----------------------------------------------------------------------------------------------------------------
Actual income tax expense $ 90,286 $ 22,737 $ 67,056 $ 66,585
================================================================================================================
75
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.
December 31, December 31, August 31,
2000 1999 1999
- -------------------------------------------------------------------------------------------
(Thousands of Dollars)
Deferred tax assets
Accrued liabilities not deductible until paid 10,425 8,383 16,856
Net operating loss carryforward 1,665 1,317 1,315
Regulatory assets 4,734 3,760 8,728
Other 4,277 1,982 3,444
- -------------------------------------------------------------------------------------------
Total deferred tax assets 21,101 15,442 30,343
Valuation allowance for net operating loss
carryforward expected to expire prior to utilization 1,230 882 880
- -------------------------------------------------------------------------------------------
Net deferred tax assets 19,871 14,560 29,463
Deferred tax liabilities
Excess of tax over book depreciation and depletion 298,492 262,515 265,493
Investment in joint ventures 11,280 11,414 7,458
Regulatory assets 78,186 75,407 66,932
Other 3,851 6,724 3,502
- -------------------------------------------------------------------------------------------
Total deferred tax liabilities 391,809 356,060 343,385
- -------------------------------------------------------------------------------------------
Net deferred tax liabilities $371,938 $341,500 $313,922
===========================================================================================
The Company has remaining net operating loss carry-forwards for income tax
purposes of approximately $22.9 million at December 31, 2000, which expire,
unless previously utilized, at various dates through the year 2010. At December
31, 2000, the Company had $7.4 million in deferred investment tax credits
recorded in other deferred credits, which will be amortized over the next 15
years.
(L) SEGMENT INFORMATION
Management has divided its operations into the following reportable segments
based on similarities in economic characteristics, products and services, types
of customers, methods of distribution and regulatory environment.
The Company conducts its operations through six segments: (1) the Marketing and
Trading segment markets natural gas to wholesale and retail customers and
markets electricity to wholesale customers; (2) the Gathering and Processing
segment gathers and processes natural gas and fractionates, stores and markets
natural gas liquids; (3) the Transportation and Storage segment transports and
stores natural gas for others; (4) the Distribution segment distributes natural
gas to residential, commercial and industrial customers and leases pipeline
capacity to others; (5) the Production segment produces natural gas and oil; and
(6) the Other segment primarily operates and leases the Company's headquarters
building and a related parking facility.
The accounting policies of the segments are substantially the same as those
described in the summary of significant accounting policies. Intersegment sales
are recorded on the same basis as sales to unaffiliated customers. All corporate
overhead costs relating to a reportable segment have been allocated for the
purpose of calculating operating income. The Company's equity method investments
do not represent operating segments of the Company. The Company has no single
external customer from which it receives ten percent or more of its revenues.
76
Gathering Transportation
Year Ended Marketing and and Other and
December 31, 2000 Trading Processing Storage Distribution Production Eliminations Total
- ----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $4,362,024 $ 839,388 $111,644 $1,270,369 $ 50,686 $ 8,747 $6,642,858
Intersegment sales 299,657 197,325 56,814 3,568 19,669 (577,033) $ --
- ----------------------------------------------------------------------------------------------------------------------------
Total Revenues $4,661,681 $1,036,713 $168,458 $1,273,937 $ 70,355 $(568,286) $6,642,858
- ----------------------------------------------------------------------------------------------------------------------------
Net revenues $ 66,482 $ 224,012 $125,582 $ 377,277 $ 70,355 $ (66,576) $ 797,132
Operating costs $ 14,321 $ 90,501 $ 44,785 $ 211,629 $ 24,228 $ (65,616) $ 319,848
Depreciation, depletion and $ 887 $ 22,692 $ 18,639 $ 67,717 $ 30,884 $ 2,532 $ 143,351
amortization
Operating income $ 51,274 $ 110,819 $ 62,158 $ 97,931 $ 15,243 $ (3,492) $ 333,933
Cumulative effect of a change $ 2,115 $ -- $ -- $ -- $ -- $ -- $ 2,115
in accounting principle,
net of tax
Income from equity $ -- $ -- $ 3,240 $ -- $ 785 $ -- $ 4,025
investments
Total assets $3,112,653 $1,507,546 $661,894 $2,007,351 $364,248 $(284,556) $7,369,136
Capital expenditures $ 59,512 $ 32,383 $ 37,701 $ 124,983 $ 34,035 $ 22,789 $ 311,403
- ----------------------------------------------------------------------------------------------------------------------------
Gathering Transportation
Four Months Ended Marketing and and Other and
December 31, 1999 and Trading Processing Storage Distribution Production Eliminations Total
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $365,224 $ 63,869 $ 13,283 $ 337,890 $ 18,692 $ 7,520 $ 806,478
Intersegment sales 17,825 15,032 25,868 1,334 4,779 (64,838) $ --
- ---------------------------------------------------------------------------------------------------------------
Total Revenues $383,049 $ 78,901 $ 39,151 $ 339,224 $ 23,471 $(57,318) $ 806,478
- ---------------------------------------------------------------------------------------------------------------
Net revenues $ 11,493 $ 19,413 $ 34,491 $ 129,870 $ 23,471 $ 59 $ 218,797
Operating costs $ 3,344 $ 8,588 $ 10,184 $ 69,455 $ 7,245 $ (6,814) $ 92,002
Depreciation, depletion and $ 242 $ 2,513 $ 5,124 $ 24,815 $ 9,715 $ 818 $ 43,227
amortization
Operating income $ 7,907 $ 8,312 $ 19,183 $ 35,600 $ 6,511 $ 6,055 $ 83,568
Income (loss) from equity $ -- $ -- $ 1,074 $ -- $ (11) $ -- $ 1,063
investments
Total assets $306,705 $368,904 $437,561 $1,776,273 $ 352,912 $ (1,115) $3,241,240
Capital expenditures $ 13,454 $ 14,613 $ 5,837 $ 34,167 $ 6,411 $ 1,534 $ 76,016
===============================================================================================================
77
Marketing Gathering Transportation
Year Ended and and and Other and
August 31, 1999 Trading Processing Storage Distribution Production Eliminations Total
- --------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $772,331 $ 72,277 $ 27,892 $ 915,782 $ 44,026 $ 6,641 $1,838,949
Intersegment sales 53,067 11,513 79,993 8,168 22,868 (175,609) $ --
- --------------------------------------------------------------------------------------------------------------
Total Revenues $825,398 $ 83,790 $107,885 $ 923,950 $ 66,894 $(168,968) $1,838,949
- --------------------------------------------------------------------------------------------------------------
Net revenues $ 35,443 $ 31,311 $102,910 $ 393,461 $ 66,894 $ (4,548) $ 625,471
Operating costs $ 9,069 $ 11,207 $ 28,919 $ 219,945 $ 19,128 $ (8,223) $ 280,045
Depreciation, depletion and $ 503 $ 3,562 $ 13,852 $ 75,443 $ 34,073 $ 2,271 $ 129,704
amortization
Operating income $ 25,871 $ 16,542 $ 60,139 $ 98,073 $ 13,693 $ 1,404 $ 215,722
Income from equity $ -- $ -- $ 1,501 $ -- $ 59 $ -- $ 1,560
investments
Total assets $273,491 $343,133 $373,742 $1,722,381 $361,806 $ (49,608) $3,024,945
Capital expenditures $ 4,196 $ 8,557 $ 32,618 $ 98,685 $ 16,046 $ 4,068 $ 164,170
- --------------------------------------------------------------------------------------------------------------
Marketing Gathering Transportation
Year Ended and and and Other and
August 31, 1999 Trading Processing Storage Distribution Production Eliminations Total
- --------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $746,744 $63,248 $ 17,399 $ 956,044 $ 31,570 $ 5,753 $1,820,758
Intersegment sales 31,870 15,309 73,302 7,784 12,312 (140,577) $ --
- --------------------------------------------------------------------------------------------------------------
Total Revenues $778,614 $78,557 $ 90,701 $ 963,828 $ 43,882 $(134,824) $1,820,758
- --------------------------------------------------------------------------------------------------------------
Net revenues $ 19,927 $25,395 $ 88,753 $ 367,453 $ 43,882 $ 229 $ 545,639
Operating costs $ 7,024 $ 7,725 $ 29,104 $ 197,590 $ 14,312 $ (580) $ 255,175
Depreciation, depletion and $ 561 $ 2,249 $ 12,818 $ 66,214 $ 18,872 $ 939 $ 101,653
amortization
Operating income $ 12,342 $15,421 $ 46,831 $ 103,649 $ 10,698 $ (130) $ 188,811
Total assets $130,100 $86,955 $351,692 $1,771,999 $282,765 $(201,024) $2,422,487
Capital expenditures $ -- $ 2,235 $ 38,271 $ 77,198 $ 16,650 $ 6,533 $ 140,887
- --------------------------------------------------------------------------------------------------------------
78
(M) QUARTERLY FINANCIAL DATA (UNAUDITED)
Total operating revenues are consistently greater during the heating season from
November through March due to the large volume of natural gas sold to customers
for heating. A summary of the unaudited quarterly results of operations for the
years ended December 31, 2000 and August 31, 1999 follows:
Year Ended First Second Third Fourth
December 31, 2000 Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------------------------
(Thousands of dollars, except per share amounts)
Operating revenues $822,713 $ 1,385,565 $ 1,754,234 $2,680,346
Operating income $105,821 $ 76,067 $ 48,525 $ 103,520
Other income (expense) $ 15,517 $ (952) $ (1,073) $ 4,983
Income taxes $ 38,446 $ 19,610 $ 5,029 $ 27,201
Net Income $ 63,022 $ 27,162 $ 10,086 $ 45,337
Earnings per share of common stock
Basic $ 1.84 $ 0.61 $ 0.03 $ 1.23
Diluted $ 1.28 $ 0.55 $ 0.03 $ 0.92
Dividends per share of common stock $ 0.31 $ 0.31 $ 0.31 $ 0.31
Average shares of common stock outstanding
Basic 29,242 29,196 29,200 29,258
Diluted 49,189 49,146 29,204 49,376
- -----------------------------------------------------------------------------------------------
Year Ended First Second Third Fourth
August 31, 1999 Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------------------------
(Thousands of dollars, except per share amounts)
Operating revenues $ 374,494 $ 591,626 $417,052 $455,777
Operating income $ 29,557 $ 124,099 $ 44,138 $ 17,928
Other income $ 5,435 $ 1,038 $ 1,028 $ 2,999
Income taxes $ 9,387 $ 44,596 $ 10,985 $ 2,088
Net Income $ 14,250 $ 68,532 $ 21,196 $ 2,379
Earnings (loss) per share of common stock
Basic $ 0.16 $ 1.87 $ 0.38 $ (0.22)
Diluted $ 0.16 $ 1.33 $ 0.38 $ (0.22)
Dividends per share of common stock $ 0.31 $ 0.31 $ 0.31 $ 0.31
Average shares of common stock outstanding
Basic 31,535 31,594 31,634 31,233
Diluted 31,578 51,687 31,640 31,233
- -----------------------------------------------------------------------------------------------
79
(N) SUPPLEMENTAL CASH FLOW INFORMATION
The table presents supplemental information relative to the Company's cash flows
for the year ended December 31, 2000, the four months ended December 31, 1999,
and the years ended August 31, 1999 and 1998.
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- -------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Cash paid during the year
Interest (including amounts capitalized) $ 111,097 $ 16,605 $ 50,498 $ 34,637
Income taxes $ 57,579 $ -- $ 59,466 $ 73,772
Noncash transactions
Treasury stock transferred to compensation plan $ -- $ 2,071 $ -- $ --
Gas received as payment in kind $ -- $ -- $ 135 $ 280
Acquisitions
Property, plant, and equipment $ 832,849 $ 17,482 $ 338,138 $ 803,370
Current assets 74,012 -- -- 232,738
Current liabilities (20,996) -- -- (42,575)
Debt assumed -- -- -- (161,698)
Regulatory assets and goodwill 17,663 -- 10,817 169,983
Lease obligation (157,651) -- -- --
Price risk management activities (239,660) -- -- --
Deferred debits -- -- -- 62,633
Deferred credits (11,313) -- -- (89,655)
Deferred income taxes -- -- (4,461) (127,744)
Capital stock -- -- -- (662,003)
- -------------------------------------------------------------------------------------------------
Cash paid $ 494,904 $ 17,482 $ 344,494 $ 185,049
=================================================================================================
(O) STOCK BASED COMPENSATION
LONG-TERM INCENTIVE PLAN - The Long-term Incentive Plan (Plan) provides for the
granting of incentive stock options, fixed stock options, stock bonus awards,
and restricted stock awards to key employees. The Company has reserved 2.4
million shares of common stock for the Plan.
Under the Plan, options may be granted by the Executive Compensation Committee
(the Committee) at any time within ten years expiring 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.
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. A
portion of the options issued to date can be exercised after one year from grant
date and must be exercised no later than ten years after grant date. Activity to
date has been as follows:
80
Weighted
Number of Average
Shares Exercise Price
- -----------------------------------------------------------------------------
Outstanding August 31, 1997 189,347 $ 25.54
Granted 262,576 $ 33.39
Exercised (96,047) $ 25.55
Expired (4,900) $ 33.94
- -----------------------------------------------------------------------------
Outstanding August 31, 1998 350,976 $ 31.30
Granted 265,724 $ 35.22
Exercised (27,950) $ 26.88
Expired (2,500) $ 34.90
Restored 35,845 $ 35.95
- -----------------------------------------------------------------------------
Outstanding August 31, 1999 622,095 $ 33.09
Granted 308,700 $ 29.16
Exercised (1,000) $ 23.69
Expired (3,000) $ 35.22
Restored 863 $ 27.38
- -----------------------------------------------------------------------------
Outstanding December 31, 1999 927,658 $ 31.78
Granted 4,000 $ 26.31
Exercised (171,411) $ 30.76
Expired (37,100) $ 32.01
Restored 27,531 $ 42.91
- -----------------------------------------------------------------------------
Outstanding December 31, 2000 750,678 $ 32.38
- -----------------------------------------------------------------------------
Options Exercisable
- -----------------------------------------------------------------------------
August 31, 1998 94,469 25.78
August 31, 1999 354,995 31.49
December 31, 1999 420,770 32.10
December 31, 2000 406,947 32.53
At December 31, 2000, the Company had 662,776 outstanding options with exercise
prices ranging between $23.69 to $35.22 and a weighted average remaining life of
7.92 years. Of these options, 346,576 were exercisable at December 31, 2000 with
a weighted average exercise price of $31.89.
The Company also had 87,902 options outstanding at December 31, 2000 with
exercise prices ranging between $35.75 and $49.56 and a weighted average
remaining life of 6.35 years. Of these options, 60,371 were exercisable at
December 31, 2000 at a weighted average exercise price of $37.19.
Under the Plans, restricted stock awards also may be granted to key officers and
employees. Ownership of the common stock vests over a three year period. Shares
awarded may not be sold during the vesting period. The fair market value of the
shares associated with the restricted stock awards is recorded as unearned
compensation in stockholders' equity and is amortized to compensation expense
over the vesting period. The dividends on the restricted stock awards are
reinvested in common stock. These shares fully vest three years after the grant
date of the restricted stock awards. The average price of shares granted was
$29.16 and $26.31 for the four months ended December 31, 1999, and the year
ended December 31, 2000, respectively.
81
Restricted stock information for 2000 and 1999 is as follows:
Number of
Shares
- -------------------------------------------------------------------------------
Outstanding August 31, 1999 --
Granted 66,300
Released to participants --
Forfeited --
Dividends 697
- -------------------------------------------------------------------------------
Outstanding December 31, 1999 66,997
GRANTED 2,000
Released to participants (3,924)
Forfeited (10,390)
Dividends 2,724
- -------------------------------------------------------------------------------
Outstanding December 31, 2000 57,407
===============================================================================
EMPLOYEE STOCK PURCHASE PLAN - In 1995, the Company authorized the Employee
Stock Purchase Plan and reserved 350,000 shares of common stock for it. In
January 2000, the Company reserved an additional 800,000 shares for the plan.
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 56 percent, 54
percent and 60 percent of eligible employees participated in the plan in fiscal
year 2000, and the years ended August 31,1999 and 1998, respectively. Under the
plan, the Company sold 261,522 shares in 2000, 88,029 shares in 1999 and 97,091
shares in 1998.
ACCOUNTING TREATMENT - The Company continues to apply APB 25 in accounting for
both plans. Accordingly, no compensation has been recognized in the consolidated
financial statements for the Company's options and the Employee Stock Purchase
Plan. 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:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- -----------------------------------------------------------------------------------
Net Income (Thousands of dollars, except per share amounts)
As reported $ 145,607 $ 35,344 $ 106,357 $ 101,795
Pro Forma $ 135,893 $ 27,066 $ 99,887 $ 98,592
Earnings per share - Diluted
As reported $ 2.96 $ 0.70 $ 2.06 $ 2.23
Pro Forma $ 2.76 $ 0.54 $ 1.94 $ 2.16
===================================================================================
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 0.2406 for fiscal year 2000, 0.2414 for the four months ended
December 31, 1999, 0.2151 for the year ended August 31, 1999 and 0.2720 for the
year ended August 31,1998. Dividend yield is estimated to be 2.6 percent for
fiscal year 2000, 1.2 percent for the four months ended December 31, 1999, 4.0
percent for the year ended August 31, 1999 and 3.9 percent for the year ended
August 31,1998, with a risk-free interest rate of 5.665 percent for fiscal year
2000, 5.664 percent for the four months ended December 31, 1999, and 5.983
percent and 6.590 percent for the years ended December 31, 1999 and 1998,
respectively.
82
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
$13.29 for the year ended December 31, 2000, $11.52 for the four months ended
December 31, 1999, and $13.86 and $8.75 for the years ended August 31, 1999 and
1998, respectively.
(P) EARNINGS PER SHARE INFORMATION
The following is a reconciliation of the numerators and denominators of the
basic and diluted EPS computations.
Year Ended Per Share
December 31, 2000 Income Shares Amount
- --------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $108,507 29,224 $ 3.71
Effect of Dilutive Securities
Options -- 24
Convertible preferred stock 37,100 19,946
-------- ------
Diluted EPS
Income available for common stock $145,607 49,194 $ 2.96
+ assumed conversion
====================================================================
Four Months Ended Per Share
December 31, 1999 Income Shares Amount
- --------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $22,977 30,425 $ 0.76
Effect of Dilutive Securities
Options -- 13
Convertible preferred stock 12,367 19,946
-------- ------
Diluted EPS
Income available for common stock $35,344 50,384 $ 0.70
+ assumed conversion
====================================================================
Year Ended Per Share
August 31, 1999 Income Shares Amount
- --------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 69,110 31,498 $ 2.19
Effect of Dilutive Securities
Options -- 20
Convertible preferred stock 37,247 20,053
-------- ------
Diluted EPS
Income available for common stock $106,357 51,571 $ 2.06
+ assumed conversion
====================================================================
83
Year Ended Per Share
August 31, 1998 Income Shares Amount
- --------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 74,816 30,674 $ 2.44
Effect of Dilutive Securities
Options -- 53
Convertible preferred stock 26,979 15,002
-------- ------
Diluted EPS
Income available for common stock $101,795 45,729 $ 2.23
+ assumed conversion
====================================================================
There were 322,380, 103,800, 104,800 and 306,300 option shares excluded from the
calculation of Diluted Earnings per Share for the year ended December 31, 2000,
the four months ended December 31, 1999, and the years ended August 31, 1999 and
1998, respectively, due to being antidilutive for the periods.
The following is a reconciliation of the basic and diluted EPS computations on
income before the cumulative effect of a change in accounting principle to net
income.
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
BASIC EPS (Per share amounts)
Income available for common stock
before cumulative effect of a
change in accounting principle $3.64 $0.76 $2.19 $2.44
Cumulative effect of a change in
accounting principle, net of tax 0.07 -- -- --
----- ----- ----- -----
Income available for common stock $3.71 $0.76 $2.19 $2.44
===== ===== ===== =====
DILUTED EPS
Income available for common stock
before cumulative effect of a
change in accounting principle $2.92 $0.70 $2.06 $2.23
Cumulative effect of a change in
accounting principle, net of tax 0.04 -- -- --
----- ----- ----- -----
Income available for common stock $2.96 $0.70 $2.06 $2.23
(Q) SUBSEQUENT EVENTS
On January 18, 2001, the Board of Directors declared a two-for-one common stock
split of one additional share of common stock for each share of common stock
outstanding to holders of record on May 23, 2001, with distribution of the split
shares expected to follow on June 11, 2001. The common stock split is subject to
shareholder approval at the 2001 annual shareholders' meeting, and accordingly,
earnings per share calculations in this report have not been restated to reflect
this stock split.
Two separate class action lawsuits have been filed against the Company in
connection with the natural gas explosions and eruptions of natural gas geysers
that occurred in Hutchinson, Kansas in January 2001. Although no assurances can
be given, management believes that the ultimate resolution of these matters will
not have a material adverse effect on its financial position or results of
operations. The Company is vigorously defending itself against all claims.
84
(R) OIL AND GAS PRODUCING ACTIVITIES
The following is historical cost information relating to the Company's
production operations:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Capitalized costs at end of year
Unproved properties $ 2,210 $ 4,224 $ 4,245 $ 3,505
Proved properties 423,824 398,748 393,096 320,055
- ----------------------------------------------------------------------------------------------------
Total capitalized costs 426,034 402,972 397,341 323,560
Accumulated depreciation, depletion and amortization 146,749 128,220 120,109 100,601
- ----------------------------------------------------------------------------------------------------
Net capitalized costs $279,285 $274,752 $277,232 $222,959
====================================================================================================
Costs incurred during the year
Property acquisition costs (unproved) $ 878 $ 103 $ 948 $ 601
Exploitation costs $ 10 $ 6 $ 17 $ 6
Development costs $ 32,817 $ 6,254 $ 13,659 $ 15,315
Purchase of minerals in place $ 4,751 $ -- $ 79,385 $151,019
- ----------------------------------------------------------------------------------------------------
The accompanying schedule presents the results of operations of the Company's
oil and gas producing activities. The results exclude general office overhead
and interest expense attributable to oil and gas production.
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net revenues
Sales to unaffiliated customers $49,868 $18,623 $42,077 $30,003
Gas sold to affiliates 19,669 4,779 22,868 12,312
- ---------------------------------------------------------------------------------------------------------
Net revenues from production 69,537 23,402 64,945 42,315
- ---------------------------------------------------------------------------------------------------------
Production costs 17,575 5,465 14,516 9,478
Exploitation costs 10 6 17 351
Depreciation, depletion and amortization 30,465 9,588 33,771 18,210
Income taxes 8,311 3,226 6,359 5,522
- ---------------------------------------------------------------------------------------------------------
Total expenses 56,361 18,285 54,663 33,561
- ---------------------------------------------------------------------------------------------------------
Results of operations from producing activities $13,176 $ 5,117 $10,282 $ 8,754
=========================================================================================================
(S) OIL AND GAS RESERVES (UNAUDITED)
Following are estimates of the Company's proved oil and gas reserves, net of
royalty interests and changes herein, for the fiscal year 2000, the four months
ended December 31, 1999, and the years ended August 31,1999 and 1998.
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.
85
Oil Gas
(MBbls) (MMcf)
- --------------------------------------------------------------------------
August 31, 1997 2,014 83,319
Revisions in 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
Revisions in prior estimates 300 8,397
Extensions, discoveries and other additions 376 37,202
Purchases of minerals in place 884 61,286
Sales of minerals in place (175) (3,057)
Production (460) (27,773)
- --------------------------------------------------------------------------
August 31, 1999 4,197 254,102
Revisions in prior estimates 18 (8,086)
Extensions, discoveries and other additions 84 9,276
Purchases of minerals in place -- --
Sales of minerals in place (1) (7)
Production (138) (8,306)
- --------------------------------------------------------------------------
December 31, 1999 4,160 246,979
Revisions in prior estimates 221 9,134
Extensions, discoveries and other additions 661 29,193
Purchases of minerals in place 215 945
Sales of minerals in place (518) (4,784)
Production (400) (26,746)
- --------------------------------------------------------------------------
December 31, 2000 4,339 254,721
==========================================================================
Proved developed reserves
August 31, 1998 2,228 134,346
August 31, 1999 2,540 175,771
December 31, 1999 2,451 169,060
December 31, 2000 2,495 182,052
- --------------------------------------------------------------------------
(T) 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.
86
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Future cash inflows $2,498,525 $ 632,751 $ 639,721 $ 423,331
Future production and development costs 400,767 194,332 194,077 129,128
Future income taxes 742,505 62,533 53,442 32,025
- ------------------------------------------------------------------------------------------------------
Future net cash flows 1,355,253 375,886 392,202 262,178
10 percent annual discount for estimated
timing of cash flows 599,370 149,527 161,156 99,549
- ------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash
flows relating to oil and gas reserves $ 755,883 $ 226,359 $ 231,046 $ 162,629
======================================================================================================
Future cash inflows are computed by applying year end prices (averaging $29.33
per barrel of oil, adjusted for transportation and other charges, and $9.98 per
Mcf of gas at December 31, 2000) to the year end quantities of proved reserves.
Subsequent to December 31, 2000, the price of natural gas has declined. The
average price in February 2001 for gas sold at market sensitive prices in North
America was approximately one-third below the year end 2000 price. As of
December 31, 2000, approximately 74 percent of anticipated gas production in
2001 has been hedged at an average price of $4.28 per Mcf. The effect of these
hedges are not reflected in the computation of future cash flows above.
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:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
- --------------------------------------------------------------------------------------------------------------
Thousands of Dollars)
Beginning of period $ 226,359 $ 231,046 $ 162,629 $ 76,611
Changes resulting from:
Sales of oil and gas produced, net of production costs (51,692) (17,938) (50,120) (32,837)
Net changes in price, development, and production costs 783,763 3,523 13,269 (6,269)
Extensions, discoveries, additions, and improved
recovery, less related costs 102,607 9,981 37,379 26,217
Purchases of minerals in place 4,751 -- 67,120 94,031
Sales of minerals in place (5,761) (24) (9,326) (142)
Revisions of previous quantity estimates 43,318 (8,454) 10,477 (2,750)
Accretion of discount 25,826 8,750 17,317 9,865
Net change in income taxes (376,438) (6,174) (11,618) 3,055
Other, net 3,420 5,649 (6,081) (5,152)
- --------------------------------------------------------------------------------------------------------------
End of period $ 755,883 $ 226,359 $ 231,046 $ 162,629
==============================================================================================================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
87
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
2001 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 2001 definitive Proxy Statement which is incorporated
herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is shown in the 2001 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 2001 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 2001 definitive Proxy Statement which is incorporated herein by
this reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
88
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) Amended 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) Certificate of Merger of ONEOK, Inc., filed April 3, 1998
(3)(e) Certificate of Merger of ONEOK, Inc., filed April 28, 2000
(3)(f) By-laws of ONEOK, Inc., as amended (Incorporated by reference
from Exhibit (3)(d) to the Company's Annual Report on Form
10-K for the year ended August 31, 1999..
(3)(g) Registration Rights Agreement dated March 1, 2000, among the
Company and the Initial Purchaser described therein,
incorporated by reference from the Registration Statement on
Form S-4 filed March 13, 2000.
(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).
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)(d) 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)(e) 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).
(4)(f) Indenture, dated September 24, 1998, between ONEOK, Inc. and
Chase Bank of Texas, incorporated by reference from Exhibit
4.1 to Registration Statement on Form S-3 filed August 26,
1998.
89
(4)(g) First Supplemental Indenture dated September 24, 1998, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from Exhibit 5(a) to Form 8-K filed September 24, 1998.
(4)(h) Second Supplemental Indenture dated September 25, 1998,
between ONEOK, Inc. and Chase Bank of Texas, incorporated by
reference from Exhibit 5(b) to Form 8-K filed September 24,
1998.
(4)(i) Third Supplemental Indenture dated February 8, 1999, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from Exhibit 4 to Form 8-K filed February 8, 1999.
(4)(j) Fourth Supplemental Indenture dated February 17, 1999, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from Exhibit 4.5 to Registration Statement on Form S-3 filed
April 15, 1999.
(4)(k) Fifth Supplemental Indenture dated August 17, 1999, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from Exhibit 4 on Form 8-K filed August 17, 1999.
(4)(l) Sixth Supplemental Indenture dated March 1, 2000, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from the Registration Statement on Form S-4 filed March 13,
2000.
(4)(m) Seventh Supplemental Indenture dated April 24, 2000, between
ONEOK, Inc. and Chase Bank of Texas, incorporated by reference
from the Registration Statement on Form 8-K filed April 24,
2000.
(10)(a) ONEOK, Inc. Long-Term Incentive Plan, incorporated by
reference from Exhibit 99 on Form 8-K dated June 18, 1999.
(10)(b) ONEOK, Inc. Stock Compensation Plan for Non-Employee
Directors, incorporated by reference from the Form S-8 filed
January 24, 2001.
(10)(c) ONEOK, Inc. Supplemental Executive Retirement Plan as amended
and restated July 1, 1999, incorporated by reference from the
Form 10-K dated August 31, 1999.
(10)(d) Termination agreements between ONEOK, Inc., and ONEOK, Inc.
Executives dated January 1, 1999, incorporated by reference
from the Form 10-K dated August 31, 1999.
(10)(e) Indemnification agreement between ONEOK Inc., and ONEOK Inc.
Officers and Directors, incorporated by reference from the
Form 10-K dated August 31, 1999.
(10)(f) Stock Option Agreement between ONEOK, Inc. and Non-Employee
Directors.
(10)(g) 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)(h) 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)(i) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May
15, 1983, incorporated by reference from Form 10-K dated
August 31, 1983.
90
(10)(j) 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)(k) 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)(l) 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)(m) 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)(n) $800,000,000 364-Day Credit Agreement date June 30, 2000,
among ONEOK, Inc., Bank of America, N.A., as Administrative
Agent and as a Bank, Letter of Credit Issuing Bank and Swing
Line Bank, Bank One, N.A., as Syndicate Agent and as a Bank
and First Union National Bank, as a document agent and as a
Bank, incorporated by reference from the Form 8-K filed July
10, 2000.
(12) Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirement for the year ended
December 31, 2000 and August 31, 1999.
(12.1) Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirement for the four months
ended December 31, 1999 and 1998.
(12)(a) Computation of Ratio of Earnings to Fixed Charges for the
year ended December 31, 2000 and August 31, 1999.
(12)(a.1) Computation of Ratio of Earnings to Fixed Charges for the
four months ended December 31, 1999 and 1998.
(21) Required information concerning the registrant's
subsidiaries.
(23) Independent Auditors' Consent
(99) ONEOK, Inc. Direct Stock Purchase and Dividend Reinvestment
Plan, incorporated by reference from the Form S-3 filed
January 30, 2001.
(2) Financial Statements Page No.
(a) Independent Auditors' Report. 54
(b) Consolidated Statements of Income for the
years ended December 31, 2000, August 31,
1999 and 1998 and the four months ended
December 31, 1999. 55
(c) Consolidated Balance Sheets at December 31,
2000 and 1999 and August 31, 1999. 56-57
(d) Consolidated Statements of Cash Flows for
the years ended December 31, 2000, August 31,
1999 and 1998 and the four months ended
December 31, 1999. 58
(e) Consolidated Statements of Shareholders'
Equity for the years ended December 31, 2000,
August 31, 1999 and 1998 and the four months
ended December 31, 1999. 59-60
(f) Notes to Consolidated Financial Statements. 61-87
91
(3) Financial Statement Schedules
All schedules are omitted because of the absence of the
conditions under which they are required.
(B) REPORTS ON FORM 8-K
December 21, 2000 - Announced that claims against the Company and
Southwest Gas Corporation asserted by Southern Union under the Federal
Rackateer Influenced and Corrupt Organizations Act (RICO) have been
dismissed.
January 19, 2001 - The Company's Board of Directors approved a
two-for-one stock split of its common stock on January 18, 2001 for
shareholders of record on May 23, 2001.
January 29, 2001 - Updated Item 7 of the Form 8-K filed on April 6,
2000, and the 8-K/A filed on June 19, 2000.
February 22, 2001 - Filed 2000 fourth quarter results in response to
questions received after the 2000 fiscal year earnings conference call.
OTHER MATTERS
None.
92
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 23rd day of March
2001.
ONEOK, Inc.
Registrant
By: /s/ JIM KNEALE
--------------
Jim Kneale
Senior Vice President, Treasurer and Chief
Financial Officer, (Principal Financial
Officer)
93
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 23rd day of
March 2001.
/s/ DAVID L. KYLE /s/ BARRY D. EPPERSON
- ----------------- ---------------------
David L. Kyle Barry D. Epperson
Chairman of the Board, Vice President, Controller and
Chief Executive Officer Chief Accounting Officer
and Director (Principal Accounting Officer)
/s/ EDWYNA G. ANDERSON /s/ BERT H. MACKIE
- ---------------------- ------------------
Edwyna G. Anderson Bert H. Mackie
Director Director
/s/ WILLIAM M. BELL /s/ DOUGLAS A. NEWSOM
- ------------------- ---------------------
William M. Bell Douglas A. Newsom
Director Director
/s/ DOUGLAS R. CUMMINGS /s/ GARY D. PARKER
- ----------------------- ------------------
Douglas R. Cummings Gary D. Parker
Director Director
/s/ J.D. SCOTT
- ----------------- --------------
John B. Dicus J. D. Scott
Director Director
/s/ WILLIAM L. FORD
- -------------------
William L. Ford
Director
/s/ DOUGLAS T. LAKE
- -------------------
Douglas T. Lake
Director
94