100 West Fifth Street
Tulsa, OK 74103
ONEOK, Inc.
2001
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
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EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2001.
OR
____TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from __________ to
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1520922
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
100 West Fifth Street, Tulsa, OK 74103
(Address of principal (Zip Code)
executive offices)
Registrant's telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Common stock, with par value of $0.01 New York Stock Exchange
(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.X
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Aggregate market value of registrant's voting stock held by non-affiliates based
on the closing trade price on March 8, 2002, was: Common stock of $ 1,167.6
million
On March 8, 2002, the Company had 60,248,668 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Documents Part of Form 10-K
Portions of the definitive proxy statement Part III
dated April 10, 2002, to be delivered to
shareholders in connection with the Annual
Meeting of Shareholders to be held
May 16, 2002.
ONEOK, Inc.
2001 ANNUAL REPORT ON FORM 10-K
Part I. Page No.
Item 1. Business 3-18
Item 2. Properties 18-22
Item 3. Legal Proceedings 23-28
Item 4. Results of Votes of Security Holders 29-30
Part II.
Item 5. Market Price and Dividends on the Registrant's 31
Common Stock and Related Shareholder Matters
Item 6. Selected Financial Data 32
Item 7. Management's Discussion and Analysis of 33-61
Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 62-63
Item 8. Financial Statements and Supplementary Data 64-105
Item 9. Changes in and Disagreements with Accountants 105
On Accounting and Financial Disclosures
Part III.
Item 10. Directors, Executive Officers, Promoters, and 106
Control Persons of the Registrant
Item 11. Executive Compensation 106
Item 12. Security Ownership of Certain Beneficial Owners and
Management 106
Item 13. Certain Relationships and Related Transactions 106
Part IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K 107-110
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 owns and operates an electric generating plant and engages in wholesale
marketing of electricity. 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
MMBtu One million British thermal units
MMMBtu/d One billion British thermal units per day
Mcf One thousand cubic feet of gas
MMcf One million cubic feet of gas
MMcf/d One million cubic feet of gas per day
Mcfe Mcf equivalent, whereby barrels of oil are converted to Mcf using six
Mcfs of natural gas to one barrel of oil
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 million barrels of oil
NGLs Natural gas liquids
Mwh Megawatt hour
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
K.Stewart Petroleum Corporation - In June 2001, the Company sold its forty
percent interest in K. Stewart Petroleum Corporation (K. Stewart), a privately
held exploration company for $7.7 million. The Company retained a production
payment on future drilling successes.
Kinder Morgan, Inc. - In April 2000, the Company acquired certain natural gas
gathering and processing assets located in Oklahoma, Kansas and West Texas from
Kinder Morgan, Inc. (KMI) and certain of its affiliates. 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 $123.5 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 an uneconomic lease obligation related to an operating lease for a
processing plant and some firm capacity lease obligations to unaffiliated
parties with out-of-market terms. 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 0.76 Bcf/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 adjustment for working capital. The current
throughput of the assets is approximately 240 MMcf/d. Production of NGLs from
the assets averages 25 MBbls/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 - In 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.
Koch - In May 1999, the Company acquired the Oklahoma midstream natural gas
gathering and processing assets of Koch Midstream Enterprises (Koch) for $285
million in cash. The assets acquired include eight natural gas processing plants
and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells
in Oklahoma.
BUSINESS SEGMENTS
The Company reports operations in the following reportable segments:
. Marketing and Trading
. Gathering and Processing
. Transportation and Storage
. Distribution
. Production
. Power
. Other
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) and its subsidiaries. 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 and firm
transportation capacity 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
U.S. However, the acquisitions during 2000 allowed the Marketing and Trading
segment to expand its presence to the west coast, Texas, throughout the Rockies,
and to the Chicago city gate areas.
OEMT was the successful bidder to supply gas to Oklahoma Natural Gas Company
(ONG), an affiliated company, for its gas sales requirements for 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 (OFS) and ONEOK NGL
Marketing L.P. (NGL Marketing). These activities are conducted primarily in
Oklahoma, Kansas and Texas. In early 2000, the Company acquired additional
gathering and processing assets including natural gas processing plants with a
combined capacity of approximately 1.6 Bcf/d, approximately 13,400 miles of
gathering lines.
Transportation and Storage - The Transportation and Storage segment provides
natural gas transportation, storage services and non-processable gas gathering.
These operations are primarily conducted through Mid Continent Market Center,
L.P. and Mid Continent Transportation, Inc. (collectively referred to as the
Market Center), ONEOK Gas Transportation, L.L.C. (OGT), ONEOK WesTex
Transmission, Inc. (WesTex), , ONEOK Gas Storage, L.L.C. (OGS), ONEOK Sayre
Storage Company (Sayre), ONEOK Texas Gas Storage L.P. (OTGS) and ONEOK Gas
Gathering, L.L.C. (OGG). Acquisitions in 2000 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. The Texas Railroad Commission (TRC)
regulates both OTGS and WesTex. In July 1999, the storage assets located in
Oklahoma were removed from regulation by the Oklahoma Corporation Commission
(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. The Market Center's operations continue to be regulated by the Kansas
Corporation Commission (KCC). In October 2001, OGG was created by the merging of
ONEOK Producer Services, L.L.C. entity and the OGT gathering assets.
Distribution - The Distribution segment provides natural gas distribution in
Oklahoma and Kansas and interstate transportation across the Oklahoma/Texas
border. The Company's distribution operations in Oklahoma and Kansas are
conducted through ONG and Kansas Gas Service (KGS), respectively, 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 population and 71 percent
of Kansas'population. OEMT, an affiliated company, was the successful bidder to
supply gas to ONG for a portion of its gas sales requirements for two to five
years beginning in November 2000. The transportation is provided by OkTex
Pipeline Company (OkTex), which is regulated by the FERC.
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 2001, the
Company participated in drilling 155 wells of which 138 were gas, 10 were oil
and 7 were dry holes.
Power - The Company's Power segment, which was created in January 2001, includes
the operating results of the peak electric generating plant constructed by the
Company. The Company's strategy is to capture the spark spread premium, which is
the value added by converting natural gas to electricity. The plant began
operation in mid-2001. The Company has a signed definitive agreement with an
unaffiliated company for a 15-year term providing the customer with the right to
purchase up to 75 megawatts per hour of the plant's generating capacity.
5
Other - The primary companies in the Other segment include ONEOK Leasing Company
and ONEOK Parking Company. ONEOK Leasing Company leases and operates the
Company's headquarters office building from an unaffiliated partnership. ONEOK
Parking Company owns and operates a parking garage adjacent to the Company's
corporate headquarters.
Environmental Matters - 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
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 period of time as negotiated with the KDHE. Through December 31, 2001,
the costs of the investigations and risk analysis related to these manufactured
gas sites have been immaterial. Although remedial investigation and interim
clean-up has begun on four sites, limited information is available about the
sites. 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 unaffiliated 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.
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 2001 totaled approximately
$472,000. There have been no material effects upon earnings or the Company's
competitive position during 2001 related to compliance with environmental
regulations.
Employees - The Company employed 3,657 persons at December 31, 2001. KGS
employed 863 people who are subject to collective bargaining contracts as of
December 31, 2001. The Company did not experience any strikes or work stoppages
during 2001. The Company's current contracts with the Unions are as follows:
Union Employees Contract Expires
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United Steelworkers of America 487 June 6, 2002
International Union of Operating Engineers 17 June 6, 2002
Gas Workers Metal Trades of the United Association of Journeyman and
Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada 11 June 6, 2002
International Brotherhood of Electrical Workers 348 June 30, 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 M of
Notes to Consolidated Financial Statements.
6
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 California border, throughout the Rockies, to the Chicago
city gate. Of the Company's consolidated revenues, revenues from unaffiliated
customers for the Marketing and Trading segment represent approximately 63.1,
65.7 and 42.0 percent for fiscal years 2001, 2000, and 1999, respectively.
Operating income from the Marketing and Trading segment, including a $37.4
million charge related to Enron, is 24.2, 15.4 and 12.0 percent of the
consolidated operating income for fiscal years 2001, 2000, and 1999,
respectively. The Marketing and Trading segment has no single external customer
from which it receives ten percent or more of consolidated revenues.
During 2001, two regulatory causes brought before the OCC related to an
affiliate, ONG, also involved the Marketing and Trading segment. The first cause
related to ONG's right to collect unrecovered purchased gas costs from the
2000/2001 winter. Under this cause, the OCC investigated whether ONG was treated
fairly in its contract with OEMT and it was determined that ONG was treated
fairly and, in fact, paid less for gas than other OEMT customers. In a second
cause, Enogex, Inc. requested a rebid of gas supply and transportation service
awarded to OEMT in November 2001 and the OCC declined to order a rebid.
The Company engages in price risk management activities. 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 is 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 statements of income. Market prices used to determine
fair value of 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.
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 leasing or ownership of storage,
generation and transportation assets. OEMT focuses on building and strengthening
supplier and customer relationships to execute their strategy.
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 that
occur during the winter heating months.
7
Price Risk Management - In order to mitigate the risks associated with energy
trading activities, 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 of Notes to Consolidated Financial
Statements for further discussion.
(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 or leases and operates 25 gas
processing plants, six of which are currently idle. It also has an ownership
interest in four gas processing plants that are operated by other owners. The
total capacity of the plants the Company owns, leases or has an ownership
interest in is 2.2 Bcf/d. In addition, the Company owns approximately 19,300
miles of natural gas gathering systems. The Company has experienced significant
growth in this segment with the acquisitions in 1999 and 2000.
The Company's operating results were significantly impacted by the acquisitions
in 1999 and 2000. Of the Company's consolidated revenues, revenues from
unaffiliated customers for the Gathering and Processing segment represent
approximately 12.0, 12.6, and 3.9 percent for fiscal years 2001, 2000, and 1999,
respectively. Operating income from the Gathering and Processing segment is
14.8, 33.2, and 7.7 percent of the consolidated operating income for fiscal
years 2001, 2000, and 1999, respectively. The Gathering and Processing segment
has no single external customer from which it receives ten percent or more of
consolidated revenues.
The gas processing operation includes the extraction of NGLs from natural gas
and the separation (fractionation) of mixed NGLs into component products
(ethane, propane, iso butane, normal butane and natural gasoline). The Company
also extracts 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 unaffiliated and affiliated
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 Btu's
extracted as NGLs with equivalent Btu's of natural gas, which keeps the producer
whole on Btu's and allows the Company to retain and sell the NGLs. Under "Fee"
contracts, the Company is paid a cash fee for gas processing.
During 2001, the Company processed an average of 1,420 MMMBtu/d of natural gas
and produced an average of 74 MBbls/d of NGLs. The Company markets its NGL
production through NGL Marketing and also purchases NGLs from third parties for
resale. During 2001, the Company sold approximately 27,719 MBbls of NGLs to a
diverse base of customers.
Market Conditions and Business Seasonality - During the year, both crude oil and
natural gas prices fell from $29.33 per barrel and $9.98 per MMBtu to $18.00 per
barrel and $1.83 per MMBtu, respectively. The downturn of the economy reduced
the demand for many NGL products, particularly ethane, which is a major
component of plastic products. Additionally, record high inventories in natural
gas and other petroleum products, such as propane, along with significantly
warmer than normal temperatures across North America during the last quarter of
2001 lowered demand for natural gas, home heating oil and propane causing weaker
prices. Many economic forecasts indicate the U.S. economy rebounding sometime in
the second half of 2002, which is supported by current forward pricing.
8
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 affiliated marketing companies, and national and local gas
gatherers, processors and marketers. Competition exists for obtaining gas
supplies for gathering and processing operations, obtaining supplies of raw
product for fractionation and the transportation of natural gas and NGLs. The
factors that affect competition typically arise as a result of the efficiency
and reliability of the operations, price and delivery capabilities.
The Company has responded to these industry conditions by acquiring assets, most
of which are strategically located near the Company's existing assets, 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.
The Gathering and Processing segment is subject to seasonality. Products used
for heating are normally more in demand during the heating months of November
through March. Accordingly, the prices of these products are 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.
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.
In May 1999, the Company acquired the Oklahoma midstream natural gas gathering
and processing assets of Koch Midstream Enterprises (Koch) for $285 million in
cash. The assets acquired include eight natural gas processing plants and
approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in
Oklahoma.
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 also 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 criteria used by the
FERC to determine a non-jurisdictional gathering facility status. The Company
can transport residue gas from its plants to interstate pipelines in accordance
with Section 311(a) of the Natural Gas Policy Act (NGPA).
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, at times, 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 NGL products. See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk and Note C of Notes to the
Consolidated Financial Statements.
9
(C) TRANSPORTATION AND STORAGE
General - ONEOK's Transportation and Storage segment provides intrastate natural
gas pipeline transportation, Section 311(a) of the NGPA interstate
transportation and storage in Oklahoma, Kansas, and Texas. ONEOK's Distribution
segment is the segment's major customer for intrastate natural gas pipeline
transportation 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 capacity of
approximately 58 Bcf.
In Oklahoma, the Company operates OGT and OGS. These companies have
approximately 3,245 miles of pipeline and five storage facilities with a
combined 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 3 Bcf of working storage capacity in the Sayre
facility for its own use. A $3.4 million expansion to increase deliverability
from the OGS Depew storage field was completed in the spring of 2000.
The Oklahoma transmission system transported 253.9 Bcf in 2001, 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 11 intra/interstate pipelines
at 27 interconnect points and connects 21 processing plants and approximately
130 producing fields allowing gas to be moved throughout the state.
In Kansas, the Company operates the Market Center with 1,711 miles of pipeline
and two gas storage facilities with approximately 5.0 Bcf of capacity. In
January 2001, Yaggy, one of the two storage facilities, was idled due to
operational and regulatory issues, idling approximately 3 Bcf of Kansas storage.
It cannot be determined at this time when the facility will resume operations. A
$10 million expansion of the Kansas transmission system was completed during
2000, which connects the Market Center system to the ONEOK-operated Bushton
natural gas processing facility and the Northern Natural Gas and ANR pipelines.
The Kansas transmission system transported 77.9 Bcf in 2001, 87.1 Bcf in 2000
and 72.8 Bcf in 1999. The Market Center provides access to the major natural gas
producing area in Kansas. The system intersects nine intra/interstate pipelines
at 18 interconnect points and connects five processing plants and approximately
three producing fields.
In Texas, the Company operates WesTex with approximately 4,733 miles of pipeline
and OTGS with three storage facilities, one of which is currently idled. Total
storage capacity is approximately 10 Bcf. Both WesTex and OTGS were acquired
from KMI in April 2000. The Texas transmission system transported 206.4 Bcf in
2001 and 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 11 intra/interstate pipelines at 32 interconnect points and connects
11 natural gas processing plants and approximately two producing fields 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. Loop, one of three storage facilities in Texas, was idled due to
operational and regulatory issues subsequent to acquisition of the facility in
2000. This idled approximately 5 Bcf of Texas storage capacity and it has not
been determined when the facility will resume operations.
ONEOK Gas Gathering, L.L.C. operates the gathering pipelines that are owned by
the Company and connected to the Company's transmission pipelines, including
gathering systems previously owned by OGT and ONEOK Producer Services, L.L.C.
Of the Company's consolidated revenues, revenues from unaffiliated customers for
the Transportation and Storage segment represent approximately 1.1, 1.7, and 1.5
percent for fiscal years 2001, 2000, and 1999, respectively. The majority of the
Transportation and Storage segment's revenues are derived from services provided
to affiliates. Operating income from the Transportation and Storage segment is
19.5, 18.6, and 27.9 percent of the consolidated operating income for fiscal
years 2001, 2000, and 1999, respectively. The Transportation and Storage segment
has no single external customer from which it receives ten percent or more of
consolidated revenues.
10
Market Conditions and Seasonality - The Transportation and Storage segment
primarily serves local distribution companies (LDC's) and large industrial
customers. 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 introduce more competition in the
natural gas markets. Factors that affect competition are location, price and the
quality of services provided. This industry is significantly affected by the
strength of the economy and price volatility. The Company believes that the
working capacity of its transportation and storage assets enables it to compete
effectively.
The Transportation and Storage segment is subject to 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, increased price volatility in
the natural gas market can mitigate the seasonality effect by influencing
decisions related to injection and withdrawal of natural gas in storage.
Government Regulations -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 and gathering 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 were removed from the Oklahoma customers' rate base and are now included
in this segment where they are being utilized in the competitive marketplace.
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 the Market Center can charge
its customers. In the first quarter of 2002, the Company filed an application
with the KCC to transfer a portion of the transportation assets of the Market
Center to KGS and the gathering assets to OFS. A final order is expected in
mid-2002.
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.
In January 2001, the Yaggy storage facility was idled due to operational and
regulatory issues related to the natural gas explosions and eruptions of natural
gas geysers. This idled approximately 3 Bcf of Kansas storage capacity. Also,
the Loop storage facility was idled due to operational and regulatory issues
subsequent to the acquisition of the facility in 2000. This idled approximately
5 Bcf of Texas' storage capacity. It has not been determined when either of the
facilities will resume operations.
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 consumers. In June 2001, the Company announced the execution of long-term
agreements between OGT and InterGen North America (InterGen) for firm
transportation service to InterGen's gas fueled Redbud Energy Facility in the
amount of 200 MMcf/d. In June 2001, commercial operation for gas transportation
began to the NRG McClain Generating Facility, which is on the OGT system, for
transportation volumes up to 85 MMcf/d.
11
Acquisitions - The Company acquired transportation and storage assets located in
Texas from KMI in April 2000. These assets are strategic assets to the Company
in part since they give the Company access to an expanded area in the Texas and
California markets.
(D) DISTRIBUTION
General - ONG distributes natural gas to wholesale and retail customers located
in the state of Oklahoma. At December 31, 2001, ONG delivered natural gas to
approximately 802,000 customers in 327 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 39 Oklahoma communities.
During 2000, the Oklahoma customers of KGS were removed from the KGS customer
base and became ONG customers.
At December 31, 2001, KGS supplied natural gas to approximately 642,000
customers in 340 communities in Kansas. It also makes wholesale delivery to 11
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 unaffiliated customers for
the Distribution segment represent approximately 22.1, 19.1 and 49.8 percent for
fiscal years 2001, 2000 and 1999, respectively. Operating income from the
Distribution segment is 18.3, 29.3 and 45.5 percent of the consolidated
operating income for fiscal years 2001, 2000 and 1999, respectively. The
Distribution segment has no single external customer from which it receives ten
percent or more of consolidated revenues.
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,
independent producers and other suppliers. 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 unaffiliated 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 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 ONG's gas supply and gas transportation needs will
continue to be met by two affiliates, OEMT for supply, and OGT for upstream
transportation service for five years.
KGS has transportation agreements for delivery of gas that have remaining terms
varying from one to twelve years with the following non-affiliated pipeline
transmission companies: Williams Gas Pipelines Central, Inc. (Williams),
Enbridge Pipelines - KPC, Inc. (KPC), Kinder Morgan Interstate Gas Transmission,
L.L.C., Panhandle Eastern Pipeline Company, Northern Natural Gas Company and
Natural Gas Pipeline of America. Additionally, approximately 20 percent of KGS's
transportation service is provided by the affiliated intrastate pipeline
companies referred to as the Market Center.
KGS has a long-term gas purchase contract with Amoco Production Company (Amoco)
for the purpose of meeting the requirements of the customers served over the
Williams pipeline system. The Company anticipates that the contract will supply
between 45 percent and 55 percent of KGS's demand served by the Williams
pipeline system. Amoco is one of various suppliers over the Williams 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
contract that exceeds the needs of the Company's residential and commercial
customer base is also available for sale to other parties, known as "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.
12
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 population and 71
percent of Kansas'population. Natural gas sold to residential and commercial
customers, which is used primarily for heating and cooking, accounts for
approximately 69 and 28 percent of gas sales, respectively in Oklahoma and 76
and 24 percent of gas sales, respectively, in Kansas.
A franchise, although non-exclusive, 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. ONG has franchises in 58 municipalities including Tulsa and
Oklahoma City while KGS holds franchises in 279 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 ONG's pipeline capacity lease (PCL) program, certain
----------
customers, for a fee, can have their gas, whether purchased from ONG or another
supplier, transported to their facilities utilizing lines owned by ONG or its
affiliates. KGS transports gas for large industrial customers through its
End-Use Customer Transportation (ECT) program. The programs allow qualifying
industrial and commercial customers to purchase gas on the spot market and have
it transported by ONG and KGS, respectively.
Because of increased competition for the transportation of gas to PCL and ECT
customers, some of these customers may be lost to affiliated or unaffiliated
transporters. If the Transportation and Storage segment gained some of this
business, it would result in a shift of some revenues from the Distribution
segment to the Transportation and Storage segment.
Competition and Business Seasonality - The natural gas industry is expected to
remain highly competitive resulting from initiatives being pursued by the
industry and regulatory agencies that allow industrial and commercial customers
increased options for energy supplies. Management believes that it must maintain
a competitive advantage in order to retain its customers and, accordingly,
continues to focus on reducing costs.
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 industrial process markets. Alternative fuels such as propane and
fuel oil also present competition. 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 provides education to customers on safety and the benefits of natural
gas, which include product performance, price and environmental impact.
The Company is subject to competition from other pipelines for its existing
industrial load. Both ONG and KGS compete for service to the large industrial
and commercial customers, however, competition continues to lower rates. A
portion of ONG's PCL services and KGS's ECT services are at negotiated rates
that are generally below the approved PCL and transportation tariff rates, and
increased competition potentially could lower these rates. Industrial and
transportation sales volumes tend to remain relatively constant throughout the
year.
13
Gas sales to residential and commercial customers are seasonal, as a substantial
portion of gas is used principally for heating. Accordingly, the volume of gas
sales is consistently higher during the heating season (November through March)
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. KGS also implemented a weather normalization
clause in December 2000, which mitigates the effect of fluctuations in weather
on revenues. The WeatherProof Bill program, implemented in September 1999 is
designed to mitigate the effect of weather fluctuations in Kansas for customers
electing to use this program.
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
Purchased Gas Adjustment (PGA) clause rate that is billed to customers. The
Company does not make a profit on the cost of gas. Other changes in costs must
be recovered through periodic rate adjustments approved by the OCC and KCC.
There were several regulatory initiatives in 2001, some due to the extraordinary
winter of 2000/2001. The highlights of these initiatives are as follows:
. The OCC issued an order denying ONG the right to collect $34.6 million
in outstanding gas costs incurred while serving customers during the
2000/2001 winter season. The Company appealed this order to the
Oklahoma Supreme Court and asked the OCC to stay the provisions of this
order pending the outcome of the Company's appeal. The OCC subsequently
approved the Company's request to stay this order, allowing ONG to
collect the $34.6 million, subject to refund should the Company
ultimately lose the case. ONEOK took a charge against fourth-quarter
earnings as a result of the Commission's order. Although the Company
will continue to assert its legal rights, it is hopeful that a
resolution of this issue can be negotiated.
. Enogex, Inc. requested that the OCC order a rebid of the gas supply and
transportation service awarded by ONG for service commencing in 2001. A
majority of both the gas supply and the transportation services had
been awarded to affiliates of ONG. The OCC determined that there was no
basis to require a rebid.
. ONG continues to take an active role in response to the OCC's Notice of
Inquiry and Notice of Proposed Rulemaking regarding the use of physical
and financial instruments to hedge against fuel procurement volatility.
ONG exercised provisions contained in a number of its gas supply
contracts that allow ONG to fix the price of a portion of its gas
supply. ONG fixed the price of approximately 40% of its anticipated
2001/2002 winter gas supply deliveries.
. ONG received approval from the OCC to create a Voluntary Fixed Price
pilot program that will enable its residential sales customers to fix
the gas cost portion of their bill for a specified winter period. The
program is being proposed for customers' 2002/2003 gas bills.
. During 2001, the KCC issued an Order extending the time period for
which gas service disconnection during inclement weather conditions
cannot be made. Due to the extension of the time period restricting
disconnections, delinquent KGS customers were allowed to continue gas
service, thus increasing uncollectible amounts. Higher gas costs in the
2000/2001 heating season also contributed to the increased
uncollectible amounts. KGS and other distribution companies in Kansas
filed a joint application with the KCC seeking approval to recover the
additional uncollectible amounts incurred during the 2000/2001 heating
season until reviewed in the next rate case. The KCC approved the
deferral allowing the companies to seek recovery of the extraordinary
uncollectible account levels experienced in the 2000/2001 winter.
KGS expects to file a rate case in late 2002. No accounting treatment
has yet been determined.
14
. KGS and the Market Center requested authorization from the KCC to
transfer a portion of the transportation assets of the Market Center to
KGS. A ruling is expected during 2002.
. 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 approved KGS's WeatherProof Bill Program for the year 2001/2002
heating season. This plan allows customers, at their discretion, to fix
their monthly payment.
. The KCC granted the Company weather normalization beginning December
2000 that mitigates weather related revenue fluctuations.
. In October 2001, the KCC entered a Suspension Order prohibiting the
recovery of a portion of KPC gas transportation service costs through
the Cost of Gas Rider. The KCC will conduct a hearing on the pass
through of those costs in May 2002. KGS is involved in related
litigation in the Kansas Court of Appeals, the FERC and the Federal
District Court in Kansas. The dispute involves a 1997 settlement
agreement entered into by KPC, KGS and the KCC staff. KGS and the KCC
staff allege KPC has failed to reduce the rates it is charging KGS in
accordance with the settlement agreement. In accordance with regulatory
"out" provisions contained in the agreement, KGS is withholding payment
to KPC to the extent KGS is not allowed to pass KPC's charges to its
customers through the cost of gas rider. KGS is currently accounting
for the costs as a deferred gas cost, offset by a deferred liability,
and not passing the costs on to customers.
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, expiring in 2014, or approximately $6.7 million annually through a
combination of a surcharge from customers and revenue from transportation under
Section 311(a) of the NGPA and other intrastate transportation revenues. There
are no significant potential claims or cases pending against the Company under
"take-or-pay" contracts.
OkTex 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. OkTex has the capacity to move up to 800 million
cubic feet per day.
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 to the maximum rate
contracts. The Company's interstate pipeline 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 has been 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.
15
Of the Company's consolidated revenues, revenues from unaffiliated customers for
the Production segment represent approximately 1.4, 0.8 and 2.4 percent for
fiscal years 2001, 2000 and 1999, respectively. Operating income from the
Production segment is 19.6, 4.6 and 6.3 percent of the consolidated operating
income for fiscal years 2001, 2000, and 1999, respectively. The Production
segment has no single external customer from which it receives ten percent or
more of consolidated revenues.
Producing Reserves - The Production segment primarily focuses its production
activities in natural gas. As of December 31, 2001, the Company had interest in
2,172 gas wells and 218 oil wells located primarily in Oklahoma, Kansas and
Texas. A number of these wells produce from multiple zones. Production increased
in 2001 as compared to 2000, primarily as a result of production from new wells
drilled.
Market Conditions and Business Seasonality - Natural gas prices at the beginning
of 2001 were at unprecedented highs. The high prices resulted in a significant
amount of drilling in the U.S. for the first half of 2001. Accordingly, lack of
rig availability delayed some developmental drilling projects for the Company.
The subsequent decline in gas prices during the second half of the year reduced
the rig shortage and allowed the Company to resume its development projects. In
addition, the Company continues to actively pursue acquisition opportunities as
a low-risk method of adding reserves.
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. In doing so, the Company competes with many large integrated oil and gas
companies and numerous independent oil and gas companies of various sizes. The
Company is in a good competitive position within its operating region due to low
finding costs and high quality production at locations near transportation
points and markets. During 2001, the segment's production was sold to a number
of affiliated and unaffiliated markets, all at market prices.
Similar to the Company's other business segments, the Production segment is
subject to seasonal factors. The Production segment's revenues are impacted by
prices, which, historically, are higher in the winter heating months when demand
is higher than in the summer and shoulder months of spring and fall. Oil prices
in the U.S. are also impacted by international production and export policies.
Property Acquisitions and Divestitures - The Company acquired $1.5 million of
properties located in the mid-continent region of the U.S. during 2001.
In June 2001, the Company sold its 40 percent equity interest in K. Stewart for
$7.7 million, recognizing a gain from the sale of $0.8 million.
Risk Management - The Company utilized derivative instruments in 2001 in order
to hedge anticipated sales of natural gas and oil production. During 2001,
approximately 74% of the Company's proved developed production was hedged with
commodity swap or option collar 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.
At December 31, 2001, the Production segment had 11 percent of its proved
developed gas production hedged for fiscal year 2002. See Item 7A. Quantitative
and Qualitative Disclosures About Market Risk and Note C of Notes to
Consolidated Financial Statements.
16
(F) POWER
General - The Company's Power segment was created in January 2001 to engage in
regional wholesale power trading in the Southwest Power Pool (SPP), Electric
Reliability Council of Texas, and Southeast Electric Reliability Council. The
Company is also a member of the Western Systems Power Pool. Transactions
conducted by the Power segment include capacity and energy. The 300-megawatt
power plant, which began operations in mid-2001, is located adjacent to one of
the Company's natural gas storage facilities and is configured to supply
electric power during peak periods with four gas-powered turbine generators
manufactured by General Electric. The Company also has leased from the SPP 200
megawatts of firm point-to-point transmission capacity from the power plant to
Entergy Services' transmission system near Fort Smith, Arkansas.
The Company has a signed definitive agreement with an unaffiliated company for a
15-year term providing the customer the right to purchase up to 75 megawatts per
hour of the plant's generating capacity.
The completed construction of this power plant complements the Company's
strategy of maximizing earnings capacity of existing assets and exploring new
opportunities that are expected to have a positive impact on earnings. Of the
Company's consolidated revenues, revenues from unaffiliated customers for the
Power segment represent approximately 0.4 percent in fiscal year 2001. Operating
income from the Power segment is 1.2 percent of the consolidated operating
income for fiscal year 2001. The Power segment has no single external customer
from which it receives ten percent or more of consolidated revenues.
Market Conditions and Business Seasonality - The Power segment primarily serves
peaking requirements in the SPP. There is currently limited competition in this
market; however, several peaking plants are currently being constructed in the
region, which will increase competition in the future. Competition typically
arises as a result of a plant's location, transmission capabilities and
operational efficiency. The Company believes that the fully operational status
of the plant, as compared to competitor plants that are still being constructed
and the plant's ability to start up quickly with its readily available gas
supply allow it to be a competitive force in its market. More importantly, the
Company believes that it serves a specific niche through cross commodity trading
natural gas and electricity in the power trading market, rather than producing
baseload electricity.
The Power segment's revenue and gross margin on power sales are subject to
seasonality due to fluctuations in sales volumes and the price of natural gas
and electricity. Electricity volumes are typically higher in the summer cooling
months than in the winter months, reflecting increased demand due to greater
cooling requirements. However, increased price volatility in the natural gas
market can mitigate the seasonality effect by influencing decisions related to
injection and withdrawal of natural gas in storage.
Price Risk Management - The Company's strategy is to capture market volatility
in the spark spread premium, which is the value added by converting natural gas
to electricity. In doing so, the Power segment uses price risk management
instruments, including 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 of Notes to Consolidated
Financial Statements.
(G) 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. The Other segment has no single external customer from which it receives
ten percent or more of consolidated revenues.
17
The Other segment includes the approximate 21 percent current ownership of
Magnum Hunter Resources, Inc. (MHR), which is currently accounted for under the
equity method. In December 2001, MHR announced a merger with Prize Energy Corp.
("Prize"). ONEOK has informed MHR that the Company will not "top-up" its
investment in the merged company, thereby decreasing its ownership to
approximately 11 percent in the merged company, and ONEOK has agreed to give up
one Director's position on the MHR Board of Directors. Assuming the merger is
completed in 2002, the Company will begin accounting for the investment in MHR
as an available for sale security and, accordingly, mark the investment to fair
value through other comprehensive income.
ITEM 2. PROPERTIES
(A) DESCRIPTION OF PROPERTY
GATHERING AND PROCESSING
The Company owns and operates or leases and operates 25 natural gas processing
plants in Oklahoma, Kansas and Texas, six of which are currently idle. It also
has an ownership interest in four natural gas processing plants that are
operated by other owners. The Company owns approximately 19,300 miles of natural
gas gathering pipeline, some of which are connected to the Company's natural gas
processing plants. The total capacity of the plants the Company owns, leases or
has an ownership interest in is 2.2 Bcf/d, of which 0.150 Bcf/d is currently
idled. The Company's natural gas processing operations utilize 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 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.
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. The Company is
rationalizing assets in non-core operating areas. Overall, the plants operated
at approximately 64 percent of capacity.
The Company owns and operates or leases and operates five NGL storage and
terminal facilities in Kansas and Texas. The total capacity of the facilities is
approximately 18,000 MBbls.
The Company owns and operates or leases and operates two fractionation
facilities in Oklahoma and Kansas. The total fractionation capacity of the two
facilities is approximately 90,000 Bbls/d.
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, 2001. 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 working storage capacity of these facilities is approximately 58
Bcf, of which 8 Bcf is currently idle. 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, 3 Bcf of working storage capacity in that facility has been retained
for the Company's use. The storage facilities in Kansas and Texas are connected
to the Company's pipelines and are located near unaffiliated intrastate and
interstate pipelines, providing the Company's storage customers with access to
multiple markets.
18
DISTRIBUTION
The Company owned approximately 16,978 miles of pipeline and other distribution
facilities in Oklahoma and approximately 12,291 miles of pipeline and other
distribution facilities in Kansas at December 31, 2001. 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 trucks 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 2,172 gas wells and 218 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 191,713 net
onshore developed leasehold acres and 40,140 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.
POWER
The Company has constructed a 300-megawatt gas-fired merchant power plant
located in Logan County, Oklahoma adjacent to an affiliate's gas storage
facility. This plant is configured to supply electric power during peak periods
with four gas-powered turbine generators manufactured by General Electric. It
began operations in mid-2001. Total costs to construct this plant totaled
approximately $120 million.
OTHER
The Company owns a parking garage and land, subject to a long-term ground lease.
Upon this land is a seventeen-story office building with approximately 517,000
square feet of net rentable space. The Company also leases its office building
under a lease term that expires in 2009 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 for the Production segment 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 for the Production segment, were as follows:
Years Ended
December 31, December 31, August 31,
Sales 2001 2000 1999
=====================================================================================================
Oil (MBbls) 492.6 400.0 460.0
Gas (MMcf) 27,578.4 26,746.0 27,773.0
-----------------------------------------------------------------------------------------------------
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 for the Production segment are as
follows:
Years Ended
December 31, December 31, August 31,
2001 2000 1999
--------------------------------------------------------------------------
Average Sales Price (a)
Per Bbl of oil $ 24.89 $ 21.43 $ 13.56
Per Mcf of gas $ 3.91 $ 2.28 $ 2.12
Average Production Costs
Per Mcfe (b) $ 0.68 $ 0.60 $ 0.49
--------------------------------------------------------------------------
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, which include
production taxes, are based on the wellhead market price, which averaged
$24.89 per Bbl of oil and $4.33 per Mcf of gas in 2001 and $29.34 per
Bbl of oil and $3.42 per Mcf of gas in 2000, instead of the weighted
average hedged price. This contributed 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 Production segment has an
interest at December 31, 2001.
Gas Oil
--------------------------------------
Gross wells 2,172 218
Net wells 622 78
--------------------------------------
Gross developed acres and net developed acres by well classification are not
available. Net developed acres for both oil and gas is 191,713 acres.
UNDEVELOPED ACREAGE
The gross and net undeveloped leasehold acreage for the Production segment at
December 31, 2001 is as follows:
Gross Net
--------------------------------------
Colorado 320 36
Kansas 1,228 538
Mississippi 2 1
Oklahoma 126,716 39,078
Texas 3,109 487
--------------------------------------
Total 131,375 40,140
--------------------------------------
Of the net undeveloped acres, approximately 38 percent is in the Anadarko Basin
area of Oklahoma and Texas, 18 percent in the Arkoma Basin area of Oklahoma and
6 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, for
the Production segment is as follows:
Years Ended
December 31, December 31, August 31,
2001 2000 1999
---------------------------------------------------------
Development
Productive 29.6 28.5 22.5
Dry 0.6 1.8 1.4
---------------------------------------------------------
Total 30.2 30.3 23.9
=========================================================
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, 2001, the Production segment was participating in the drilling
of 6 wells. The Company's net interest in these wells amounts to 0.53 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. On June 21, 1999, ONEOK, Inc. ("ONEOK") was
served with a Complaint filed by Jack J. Grynberg ("Grynberg"), purportedly on
behalf of the United States pursuant to the False Claims Act (31 U.S.C. [sect]
729, et seq.). Similar complaints were filed against approximately 65 other
companies that measure natural gas extracted from lands owned by the federal
government or American Indian tribes. The gravamen of the complaints is that,
since at least 1985, the defendants have systematically undermeasured the
volumes and/or the heating content of gas purchased from federal and Indian
lands, resulting in underpayment of royalties due the federal government and
the various Indian tribes. Grynberg seeks to recover the underpayments,
interest, treble damages, costs, including attorneys' fees, and civil penalties
in the amount of $5,000 to $10,000 for each violation of the False Claims Act.
The actions brought by Grynberg, together with certain other actions alleging
underpayment of royalties to federal and Indian lessors, have been assigned to
a multidistrict litigation (MDL) proceeding in the United States District Court
for the District of Wyoming for coordination of pretrial proceedings. The Court
has overruled the defendants' Motions to Dismiss, but has not yet established
a scheduling order for further proceedings. No discovery relating to claims
against ONEOK has commenced in the case and ONEOK intends to vigorously defend
all aspects of claims made against it in this litigation.
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 No. 99-5103. On May 5, 1999, ONEOK, Inc. ("ONEOK") filed
a Complaint against Southern Union Company ("Southern Union") alleging that
Southern Union had breached the February 21, 1999 Confidentiality and Standstill
Agreement (the "Agreement") between Southern Union and Southwest Gas Corporation
("Southwest") and had tortiously interfered with the ONEOK-Southwest merger.
ONEOK alleged that it is a third-party beneficiary of the Agreement. ONEOK also
sought to enjoin Southern Union from breaching the 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 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 Agreement was unenforceable; and (2) a declaratory
judgment determining that Southern Union had not breached the Agreement. The
Court held a status conference on August 31, 2000, and granted Southern Union's
Motion to Transfer the action to the federal district court in Arizona. 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. Following transfer to Arizona, by Order filed June 5,
2001, this case was consolidated with Southern Union Company v. Southwest Gas
Corporation, et al., Case No. CIV-99-1294-PHX-ROS, described below. On June 29,
2001, Southern Union filed a Motion for Summary Judgment on all of the claims
asserted by ONEOK against Southern Union; in an Order dated January 4, 2002, the
Court, among other things, granted Southern Union's Motion for Summary Judgment
against ONEOK. Southern Union's counterclaims have not been ruled upon by the
Court, but appear to have no further legal effect.
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 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
23
M. Irvin ("Irvin") and Jack D. Rose ("Rose"). Southern Union alleged (1) that
the action arose out of a fraud and 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. [sect].[sect] 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 Eugene N. Dubay and John A. Gaberino,
Jr. 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 ground
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 were thereafter filed to apply the Court's
December 15, 2000 ruling to the other defendants and to Southern Union's state
RICO claims; by Order filed May 23, 2001, the Court applied the December 15,
2000 ruling as to all defendants and dismissed Southern Union's state RICO
claims against all defendants. In an Order dated June 21, 2001, the Court, among
other things, granted the Motions to Dismiss all of Southern Union's claims
against ONEOK, Eugene N. Dubay, and John A. Gaberino, Jr. except the claim for
tortious interference with business relations and, as to Eugene N. Dubay and
John A. Gaberino, Jr., the claim for tortious interference with contract. On or
about June 29, 2001, ONEOK, Eugene N. Dubay, and John A. Gaberino, Jr. filed
Motions for Summary Judgment. In an Order filed September 26, 2001, the Court,
among other things, granted the Motions for Summary Judgment by ONEOK, Eugene N.
Dubay, and John A. Gaberino, Jr. on Southern Union's
24
claim for tortious interference with business relations to the extent Southern
Union is seeking lost profits damages for the failed merger with Southwest but
denied the motion to the extent Southern Union is seeking out-of-pocket and
punitive damages; and granted the Motions for Summary Judgment by Eugene N.
Dubay and John A. Gaberino, Jr. on Southern Union's claim for tortious
interference with contract. At this point, Southern Union's only remaining claim
against ONEOK, Eugene Dubay and John A. Gaberino, Jr. is for out-of-pocket
damages and punitive damages based on alleged tortious interference with a
business relationship. Under the current Scheduling Order, final Motions for
Summary Judgment may be filed by April 30, 2002 and trial is scheduled to
commence on October 15, 2002. ONEOK expects to file a Motion for Summary
Judgment seeking a dismissal of the remaining claims of Southern Union,
including the claim for punitive damages. Based on discovery in the cases at
this point, ONEOK believes that Southern Union's out-of-pocket damages
potentially recoverable at trial, exclusive of legal fees and expenses, are
less than $1,000,000. As in all litigation, judgments of the Court are
potentially subject to appeal by the parties.
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, Inc. ("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. On August 23, 2000, ONEOK filed its
First Amended Complaint against Southwest, adding allegations that Southwest had
fraudulently induced ONEOK to enter into the Amended Merger Agreement with
Southwest and had breached the Merger Agreement. At a status conference held on
August 31, 2000, the Court heard argument on and granted Southwest's Motion to
Transfer the action to the federal district court in Arizona. Southwest's filed
its Amended Answer to ONEOK's First Amended Complaint on or about May 7, 2001,
denying all claims. Following transfer to Arizona, by Order filed June 5, 2001,
this case was consolidated with Southern Union Company v. Southwest Gas
Corporation, et al., Case No. CIV-99-1294-PHX-ROS, described above. On or about
June 29, 2001, Southwest filed a Motion for Summary Judgment on ONEOK's claims
against Southwest. In an Order dated January 4, 2002, the Court, among other
things, granted Southwest's Motion for Summary Judgment as to ONEOK's claims
against Southwest for breach of contract and rescission, but denied Southwest's
Motion for Summary Judgment as to ONEOK's claim against Southwest for fraudulent
inducement. Under the current Scheduling Order, final Motions for Summary
Judgment may be filed by April 30, 2002 and trial is scheduled to commence on
October 15, 2002.
Southwest Gas Corporation v. ONEOK, Inc., No. 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, Inc. ("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 make certain disclosures to the Southwest Board; (4) if ONEOK had made
such disclosures, it would have caused the Board of Southwest to have questions
about the chances of obtaining regulatory approvals and the Southwest Board
might not have entered into an amendment of the Merger Agreement and the Board
would have demanded ONEOK cure its breach of the Merger Agreement; (5) ONEOK's
failure 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: (i) fraud in the inducement; (ii) fraud;
(iii) breach of contract; (iv) breach of implied covenant of good faith and fair
dealing; and (v) 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
25
$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. On or about April 16, 2001, ONEOK filed its Answer to
Southwest's First Amended Complaint, and Counterclaims against Southwest
reasserting, in essence, the claims ONEOK asserts against Southwest in Case No.
CIV-00-1775-PHX-ROS, described above. On or about June 29, 2001, Southwest filed
a Motion for Partial Summary Judgment in its favor on its claims against ONEOK
for breach of contract and breach of the implied covenant of good faith and fair
dealing. Also on or about June 29, 2001, ONEOK filed a Motion for Summary
Judgment on Southwest's claims against ONEOK. In an Order dated January 4, 2002,
the Court, among other things, (i) denied Southwest's Motion for Partial Summary
Judgment in its favor on its claims against ONEOK for breach of contract and
breach of the implied covenant of good faith and fair dealing; (ii) granted
ONEOK's Motion for Summary Judgment against Southwest with respect to
Southwest's claim for "benefit-of-the-bargain" or "price differential damages"
(i.e., damages measured by the difference between the ONEOK-Southwest Merger
Agreement price per share and the market value of Southwest's shares following
termination of the Merger Agreement); and (iii) denied ONEOK's Motion for
Summary Judgment in part with respect to Southwest's claims for fraud in the
inducement and fraud. Under the current Scheduling Order, final Motions for
Summary Judgment may be filed by April 30, 2002 and trial is scheduled to
commence on October 15, 2002. Based on discovery in the cases at this point,
ONEOK believes that Southwest's actual damages potentially recoverable at trial,
exclusive of legal fees and expenses, are less than $5,500,000. As in any
litigation, judgments of the Court are potentially subject to appeal by the
parties.
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, Inc.
("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 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.
Quinque Operating Company, et al. v. Gas Pipelines, et al., 26/th/ Judicial
-----------------------------------------------------------
District, District Court of Stevens County, Kansas, Civil Department, Case No.
99C30. On June 8, 2001, a Second Amended Petition was filed as a purported class
action against approximately 225 defendants, including ONEOK, Inc. (the
"Company"), one of its
26
divisions and five of its subsidiaries. The Second Amended Petition was
purportedly filed on behalf of all producers and royalty owners who have lost
money as a result of alleged mismeasurement of gas since 1974 from any of the
approximately 225 defendants. The Second Amended Petition alleges that each of
the approximately 225 defendants engaged in one or more specific "mismeasurement
techniques" and conspired with one another to undermeasure the gas sold by the
alleged class members. The Second Amended Petition alleges that the aggregate
alleged underpayment to all purported class members since 1974 is estimated to
be tens of billions of dollars. One of the named subsidiaries of the Company,
ONEOK WesTex Transmission, Inc. ("ONEOK WesTex"), is a former subsidiary of
Kinder Morgan, and Kinder Morgan has agreed to assume the defense of ONEOK
WesTex while reserving its rights and denying that it has any obligation to
indemnify the Company against any loss suffered by ONEOK WesTex as a result of
this litigation. Another of the named subsidiaries of the Company, ONEOK
Resources Company, was voluntarily dismissed as a defendant on December 4, 2001,
because that subsidiary does not measure gas for pay purposes. Numerous other
defendants also have been voluntarily dismissed for the same reason. Discovery
in the case, except as to class certification and personal jurisdiction issues,
has been stayed. Plaintiffs and defendants, including the ONEOK defendants,
have served and responded to various discovery requests on the personal
jurisdiction and class certification issues. (One of the ONEOK defendants,
ONEOK Gas Transportation, LLC, is contesting personal jurisdiction.) The
defendants, including the ONEOK defendants, also have filed a Motion to Dismiss
the action, asserting various legal defenses to plaintiffs' claims. That motion
has been fully briefed and was argued before the Court on November 29, 2001,
and we are awaiting the Court's decision on it. In February 2002, plaintiffs
filed a motion to file a Third Amended Petition, in order to add certain
plaintiffs, dismiss Quinque Operating Company as a plaintiff, and amend certain
of their substantive allegations. On February 21, 2002, the Court entered an
Order allowing the filing of the plaintiff's Third Amended Petition. The Company
intends to vigorously defend all aspects of the claims asserted in this case.
Application of Michael Edward McAdams and John Powell Walker for Relief from
----------------------------------------------------------------------------
Improper and Excessive Gas Costs, Cause No. PUD 980000188, before the Oklahoma
---------------------------------
Corporation Commission. On April 6, 1998, the Applicants filed an Application,
naming ONG as the Respondent, requesting that the Commission review the gas
purchase contract between ONG and Dynamic Energy Resources, Inc. (which was
subsequently assigned by Dynamic to Enogex, Inc., and to Associated Natural Gas,
Inc. (now Duke Energy)). Applicants allege that ONG has charged and continues to
charge its ratepayers, through its PGA, excessive, imprudent and unwarranted gas
purchase costs related to that contract. Applicants seek, on behalf of all
ratepayers, a determination of whether ONG is passing excessive, imprudent gas
costs through to its customers, and if so, to order refunds or prospective
adjustments warranted to compensate the ratepayers for past and on-going
overcharges. The Consumer Services Divisions ("CSD") of the Commission is also
conducting a review of the contract. Applicants filed their direct testimony on
February 21, 2002, alleging that ONG's liability to its ratepayers is $100.4
million. Of this amount, $44.8 million represents the alleged excess amount paid
under the contract, and $55.6 million represents the opportunity cost of funds
incurred by the ratepayers as a result of the alleged overcharges. CSD filed its
direct testimony on February 25, 2002 alleging excess costs under the contract
of $45 million and interest thereon in the amount of $22 million. CSD also
alleged that ONG passed on excess costs from five other contracts (including the
old Creek Systems contract) in the amount of $53 million which they recommended
the OCC pursue. ONG is to file rebuttal testimony on April 21, 2002. The hearing
before the Commission en banc and/or an ALJ is scheduled June 3, 2002.
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 Gilley et al.
-------------
v. Kansas Gas Service Company, Western Resources, Inc. ONEOK, Inc. ONEOK Gas
----------------------------------------------------------------------------
Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation
---------------------------------------------------------------------------
L.L.C. and Mid-Continent Market Center, Inc., Case No. 01 C 0157 in the District
--------------------------------------------
Court of Reno County, Kansas. Two separate class action lawsuits were filed
against ONEOK and several of its affiliates in early 2001 relating to certain
gas explosions in or near Hutchinson, Kansas. The plaintiffs seek to certify two
separate classes of claimants, which include all owners of real estate in Reno
County, Kansas whose property had allegedly declined in value, and owners of
businesses in Reno County whose income had allegedly suffered. The petitions
seek recovery on
27
behalf of the class claimants for an amount which will fully and fairly
compensate all members of the class. In addition to the foregoing cases, there
are four other cases filed against ONEOK or other subsidiaries of ONEOK seeking
property damage, personal injury, wrongful death claims and punitive damages
relating to the gas explosion in or near Hutchinson, Kansas. ONEOK and its
subsidiaries are being represented by their insurance carrier in these cases.
At this point in discovery, ONEOK is unable to evaluate the merits of these
cases or likelihood of success by the plaintiffs.
28
ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS
(A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the Company's security holders, through
the solicitation of proxies or otherwise, during the fourth quarter of the
fiscal year covered by this report.
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 successors are duly elected.
Name and Position Age Business Experience In Past Five Years
---------------------------------------------------------------------------------------------------------------------
David L. Kyle 49 2000 to present Chairman of the Board of Directors, President, and Chief Executive Officer
Chairman of the Board, 1997 to 2000 President and Chief Operating Officer
President and Chief 1995 to present Member of the Board of Directors
Executive Officer 1994 to 1997 President and Chief Operating Officer of Oklahoma Natural Gas Company
---------------------------------------------------------------------------------------------------------------------
James C. Kneale 50 2001 to present Senior Vice President, Treasurer, and Chief Financial Officer
Senior Vice President, 1999 to 2000 Vice President, Treasurer, and Chief Financial Officer
Treasurer, and Chief 1997 to 1999 President and Chief Operating Officer of Oklahoma Natural Gas Company
Financial Officer 1996 to 1997 Vice President of ONEOK Resources Company
---------------------------------------------------------------------------------------------------------------------
John A. Gaberino, Jr. 60 2001 to present Senior Vice President, General Counsel, and Corporate Secretary
Senior Vice President, 1998 to 2001 Senior Vice President and General Counsel
General Counsel, and 1994 to 1998 Stockholder, Officer and Director of Gable & Gotwals
Corporate Secretary
---------------------------------------------------------------------------------------------------------------------
Edmund J. Farrell 58 2001 to present Senior Vice President -- Administration
Senior Vice President -- 1999 to 2001 President and Chief Operating Officer of Oklahoma Natural Gas Company
Administration 1997 to 1999 Vice President of ONEOK Gas Marketing Company
1996 to 1997 Vice President -- Customer Services of Oklahoma Natural Gas Company
---------------------------------------------------------------------------------------------------------------------
John W. Gibson 49 2000 to present President -- Energy, ONEOK, Inc. (1)
President -- Energy 1996 to 2000 Executive Vice President, Koch Energy, Inc.; President, Koch Midstream Services;
President, Koch Gateway Pipeline Company
---------------------------------------------------------------------------------------------------------------------
Christopher R Skoog 38 1999 to present President -- ONEOK Energy Marketing and Trading Company, II
President -- ONEOK 1995 to 1999 Vice President -- ONEOK Gas Marketing Company
Energy Marketing and
Trading Company, II
---------------------------------------------------------------------------------------------------------------------
J.D. Holbird 52 1999 to present President -- ONEOK Resources Company
President -- ONEOK 1997 to 1999 Vice President -- ONEOK Resources Company
Resources Company 1996 to 1997 Vice President -- Tulsa District Oklahoma Natural Gas Company
---------------------------------------------------------------------------------------------------------------------
Eugene N. Dubay 53 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
Kansas Gas Service
Company
---------------------------------------------------------------------------------------------------------------------
Samuel Combs, III 44 2001 to present President and Chief Operating Officer of Oklahoma Natural Gas Company
President and Chief 1999 to 2001 Vice President Western Region Oklahoma Natural Gas Company
Operating Officer of 1996 to 1999 Vice President -- Oklahoma City District Oklahoma Natural Gas Company
Oklahoma Natural Gas
Company
---------------------------------------------------------------------------------------------------------------------
29
------------------------------------------------------------------------------------------------------------------
Beverly Monnet 43 2001 to present Vice President, Controller and Chief Accounting Officer
Vice President, 1997 to 2001 Manager of Accounting ONEOK Resources Company
Controller and Chief 1995 to 1997 Manager of Gas Accounting of Oklahoma Natural Gas Company
Accounting Officer
------------------------------------------------------------------------------------------------------------------
(1) The Energy group includes the Gathering and Processing and
Transportation and Storage segments.
No family relationships exist between any of the executive officers nor any
arrangement or understanding between any executive officer and any other person
pursuant to which the officer was selected.
30
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 sales prices of the Company's common stock for each
fiscal quarter during the last two fiscal years were as follows:
Years Ended
December 31, 2001 December 31, 2000
------------------------------------------------------------------------
High Low High Low
------------------------------------------------------------------------
First Quarter $ 24.34 $ 18.13 $ 13.78 $ 10.88
Second Quarter $ 22.50 $ 19.01 $ 15.07 $ 12.32
Third Quarter $ 20.48 $ 14.17 $ 19.89 $ 13.16
Fourth Quarter $ 18.40 $ 16.15 $ 25.28 $ 19.25
------------------------------------------------------------------------
The high and low sales prices for the year ended December 31, 2000 and the
first and second quarters for the year ended December 31, 2001 have been
restated to give the effect of the 2001 two-for-one stock split.
(B) HOLDERS
There were 14,454 holders of the Company's common stock at March 8, 2002.
(C) DIVIDENDS
Quarterly dividends declared on the Company's common stock during the last two
fiscal years were as follows:
Years Ended
December 31, December 31,
2001 2000
--------------------------------------------------------
First Quarter $ 0.155 $ 0.155
Second Quarter $ 0.155 $ 0.155
Third Quarter $ 0.155 $ 0.155
Fourth Quarter $ 0.155 $ 0.155
--------------------------------------------------------
The quarterly dividends for the year ended December 31, 2000 and the first and
second quarters of the year ended December 31, 2001 have been restated to give
the effect of the 2001 two-for-one stock split.
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, $188.9
million of retained earnings is so restricted. On December 31, 2001, $226.6
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.
31
ITEM 6. SELECTED FINANCIAL DATA
Following are selected financial data for the Company for each of the last five
years and the transition period.
In accordance with a pronouncement of the Financial Accounting Standards Board's
Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF
Topic No. D-95 (Topic D-95), the Company revised its computation of earnings per
common share (EPS). The Company restated the EPS amounts for all periods to be
consistent with the revised methodology and to give effect of the two-for-one
stock split in 2001. See Note Q of the Notes to the Consolidated Financial
Statements.
Years Ended Years Ended
December 31, August 31,
---------------------------- -------------------------------------------
2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------
(Millions of Dollars, except per share amounts)
Operating revenues $ 6,803.1 $ 6,642.9 $ 1,838.9 $ 1,820.8 $ 1,161.6
Operating income $ 295.2 $ 333.9 $ 215.7 $ 188.8 $ 127.8
Net income $ 101.6 $ 145.6 $ 106.4 $ 101.8 $ 59.3
Total assets $ 5,879.2 $ 7,360.3 $ 3,024.9 $ 2,422.5 $ 1,237.4
Long-term debt $ 1,742.8 $ 1,350.7 $ 837.0 $ 329.3 $ 347.1
Basic earnings per share $ 0.85 $ 1.23 $ 0.86 $ 0.96 $ 1.07
Diluted earnings per share $ 0.85 $ 1.23 $ 0.86 $ 0.96 $ 1.07
Dividends per common share $ 0.62 $ 0.62 $ 0.62 $ 0.60 $ 0.60
Percent of payout 72.9% 50.4% 72.1% 62.5% 56.1%
Ratio of earnings to fixed charges 2.01x 2.88x 4.06x 5.50x 3.51x
Ratio of earnings to combined fixed charges
and preferred stock dividend requirements 1.43x 1.93x 1.93x 2.52x 3.48x
----------------------------------------------------------------------------------------------------------------------
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
Basic earnings per share $ 0.27 $ 0.26
Diluted earnings per share $ 0.27 $ 0.26
Dividends per common share $ 0.155 $ 0.155
Percent of payout 57.4% 59.6%
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
----------------------------------------------------------------------------------------------
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Some of the statements contained and incorporated in this Form 10-K are
forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995. The forward-looking statements relate to the
anticipated financial performance, management's plans and objectives for future
operations, business prospects, outcome of regulatory proceedings, market
conditions and other matters. The Private Securities Litigation Reform Act of
1995 provides a safe harbor for forward-looking statements in various
circumstances. The following discussion is intended to identify important
factors that could cause future outcomes to differ materially from those set
forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding
paragraph, the information concerning possible or assumed future results of
operations and other statements contained or incorporated in this Form 10-K
identified by words such as "anticipate," "estimate," "expect," "intend,"
"believe," "projection" or "goal."
You should not place undue reliance on the forward-looking statements. They are
based on known and unknown risks, uncertainties and other factors that may
cause our actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or
implied by the forward-looking statements. Those factors may affect our
operations, markets, products, services and prices. In addition to any
assumptions and other factors referred to specifically in connection with the
forward-looking statements, factors that could cause our actual results to
differ materially from those contemplated in any forward-looking statement
include, among others, the following:
.. the effects of weather and other natural phenomena on sales and prices;
.. increased competition from other energy suppliers as well as alternative
forms of energy;
.. the capital intensive nature of the Company's business;
.. further deregulation, or "unbundling" of the natural gas business;
.. competitive changes in the natural gas gathering, transportation and
storage business resulting from deregulation, or "unbundling," of the
natural gas business;
.. the profitability of assets or businesses acquired by the Company;
.. risks of marketing, trading, and hedging activities as a result of
changes in energy prices and credit worthiness of counterparties;
.. economic climate and growth in the geographic areas in which the
Company does business;
.. the uncertainty of gas and oil reserve estimates;
.. the timing and extent of changes in commodity prices for natural gas,
natural gas liquids, electricity, and crude oil;
.. the effects of changes in governmental policies and regulatory actions,
including income taxes, environmental compliance, and authorized rates;
.. the results of litigation related to the Company's now terminated
proposed acquisition of Southwest Gas Corporation (Southwest) or to the
termination of the Company's merger agreement with Southwest;
.. the results of administrative proceedings and litigation involving the
Oklahoma Corporation Commission and Kansas Corporation Commission; and
.. 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.
Other factors and assumptions not identified above were also involved in the
making of the forward-looking statements. The failure of those assumptions to
be realized, as well as other factors, may also cause actual results to differ
materially from those projected.
33
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, while
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.
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 expanded its trading capabilities by marketing and trading energy from
its 300 megawatt, gas-fired electric generating plant designed to capture the
spark spread premium, which is the value added by converting natural gas to
electricity, primarily during peak demand periods.
OPERATING HIGHLIGHTS
Acquisitions and Capital Expenditures - The Company increased its common
ownership interest in Magnum Hunter Resources, Inc. (MHR) from approximately
nine percent to over twenty-one percent in early 2001 through conversion of
shares and redemption of MHR preferred stock owned by the Company to shares of
MHR common stock as well as exercising warrants. As a result, the Company began
accounting for the MHR investment using the equity method of accounting. In
December, 2001, MHR and Prize Energy Corp. (Prize) announced plans to merge
which will reduce the Company's ownership to approximately 11 percent. Assuming
the merger is completed in 2002, the Company will begin accounting for the
investment in MHR as an available for sale security and, accordingly, mark the
investment to fair value through other comprehensive income. The MHR investment
and related income is reported in the Other segment.
During 2001, the Company completed construction of the $120 million Spring
Creek Power Plant, located in Logan County, Oklahoma, and began operations in
mid-2001. Four gas-powered turbines will provide electricity during peak demand
periods. The Company spent approximately $42.3 million in 2001, $58.7 million
in 2000, $13.4 million in the four months ended December 31, 1999 and $3.7
million in the year ended August 31, 1999 constructing the 300 megawatt plant
In 2000, 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 complement
and strengthen each other.
Regulatory- KGS was successful in obtaining temporary approval of weather
normalization. KGS also obtained 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 reduce the
impact of weather on earnings and customer bills.
34
The OCC issued an order denying ONG the right to collect $34.6 million in
unrecovered gas costs incurred while serving customers during the 2000/2001
winter season. The Company appealed this order to the Oklahoma Supreme Court
and asked the OCC to stay the provisions of this order pending the outcome of
the Company's appeal. The OCC subsequently approved the Company's request to
stay this order, which will allow ONG to collect the $34.6 million, subject to
refund should the Company ultimately lose the case. Although the Company will
continue to assert its legal rights, it is hopeful that a resolution of this
issue can be negotiated.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of financial condition and operations are based on
our consolidated financial statements, prepared in accordance with accounting
principles generally accepted in the United States of America and contained
within this report. Certain amounts included in or affecting our financial
statements and related disclosure must be estimated, requiring us to make
certain assumptions with respect to values or conditions which cannot be known
with certainty at the time the financial statements are prepared. Therefore,
the reported amounts of our assets and liabilities, revenues and expenses and
associated disclosures with respect to contingent assets and obligations are
necessarily affected by these estimates. We evaluate these estimates on an
ongoing basis, utilizing historical experience, consultation with experts and
other methods we consider reasonable in the particular circumstances.
Nevertheless, actual results may differ significantly from our estimates. We
believe that certain accounting policies are of more significance in our
financial statement preparation process than others as discussed below.
Energy Trading and Risk Management Activities - The Company engages in price
risk management activities. As discussed in Note A of Notes to Consolidated
Financial Statements under "Energy Trading and Risk Management Activities",
energy trading contracts are accounted for 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 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. For further
information, see Note C of Notes to Consolidated Financial Statements.
Regulation - The Company's intrastate transmission pipelines and distribution
operations are subject to the rate regulation and accounting requirements of
the OCC, KCC and TRC. Certain other transportation activities of the Company
are subject to regulation by the FERC. Allocation of costs and revenues to
accounting periods for rate-making and regulatory purposes may differ from
bases generally applied by non-regulated 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 they are recovered through rates. Although no
further unbundling of services is anticipated, should this occur, certain of
these assets may no longer meet the criteria for deferred recognition and,
accordingly, a write-off of regulatory assets and stranded costs may be
required.
35
Impairments - The Company assesses for impairment of long-lived assets when
indicators of impairment are present. An impairment is recognized if the
undiscounted cash flows are not sufficient to recover the assets carrying
amount. 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.
See further discussion of the Company's significant accounting policies in Note
A of Notes to the Consolidated Financial Statements.
CONSOLIDATED OPERATIONS
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
-------------------------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Operating revenues $ 6,803,146 $ 6,642,858 $ 1,838,949
Cost of gas 5,894,361 5,845,726 1,213,478
-------------------------------------------------------------------------------------------------------------
Net revenues 908,785 797,132 625,471
Operating costs 456,243 319,848 280,045
Depreciation, depletion, and amortization 157,310 143,351 129,704
-------------------------------------------------------------------------------------------------------------
Operating income $ 295,232 $ 333,933 $ 215,722
=============================================================================================================
Other income, net $ 876 $ 18,475 $ 10,500
=============================================================================================================
Cumulative effect of a change in accounting principle $ (3,508) $ 3,449 $ -
Income tax 1,357 (1,334) -
-------------------------------------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle, net of tax $ (2,151) $ 2,115 $ -
=============================================================================================================
Operating Results - A full year of operations of the assets acquired in March
and April of 2000 contributed to increased net revenues, despite lower energy
prices in the latter part of 2001, and increased operating costs and
depreciation, depletion and amortization. The Company's ability to successfully
execute its transportation and storage arbitrage strategy also continued to
favorably impact operating results. The impact of the OCC ruling related to the
recovery of gas costs from the 2000/2001 winter reduced operating income by
$34.6 million and the impact of the Enron bankruptcy reduced operating income
by $37.4 million in 2001. The Company is pursuing all opportunities to settle
the OCC matter. Included in Other income, net for 2001 is $8.1 million in
income from equity investments including MHR and $3.7 million of ongoing
litigation costs associated with the terminated acquisition of Southwest Gas
Corporation. The reduction in the effective tax rate for 2001 is the result of
changes in estimates of prior year tax liabilities recorded in the third
quarter.
The Company's operating results during 2000 increased compared to 1999 due to
the acquisitions, greater price volatility in the U.S. natural gas markets,
adoption of mark-to-market accounting for its trading activities, and higher
natural gas and natural gas liquids prices. Operating costs and depreciation,
depletion, and amortization increased primarily due to the acquisitions.
Included in Other income, net for 2000 is the $26.7 million gain on the sale of
Indian Basin, $13.4 million in income from equity investments and preferred
dividends received and $13.7 million of previously deferred transaction and
ongoing litigation costs associated with the terminated acquisition of
Southwest Gas Corporation.
Interest expense increased in 2001 compared to 2000 as a result of increased
debt primarily due to financing of acquisitions and increased working capital
including unrecovered purchased gas costs. The Company has interest rate swaps
in place that reduced interest expense by $5.3 million in 2001 from what the
expense would have been with fixed interest rates. See Note C in the Notes of
Consolidated Financial Statements for further discussion of interest rate swaps.
36
Transition Period Operating Results
Four Months Ended
December 31,
1999 1998
-----------------------------------------------------------------------
Financial Results (Thousands of Dollars)
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 offset much of the margin variances caused by
weather. This revenue was recorded in the Other segment. The operations from
the assets acquired in 1999 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.
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 Company has mid-continent region storage
positions and transport capacity of 1 Bcf/d that allows for trade from the
California border, throughout the Rockies, to the Chicago city gate. With total
storage capacity of 73 Bcf, withdrawal capability of 2.1 Bcf/d and injection
capability of 1.4 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 Company continues to enhance its strategy
of focusing on higher margin business which includes providing reliable service
during peak demand periods through the use of storage.
37
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Gas sales $ 4,906,556 $ 4,658,787 $ 821,890
Cost of gas 4,804,795 4,595,199 789,955
----------------------------------------------------------------------------------------------------------------------
Gross margin on gas sales 101,761 63,588 31,935
Other revenues 1,668 2,894 3,508
----------------------------------------------------------------------------------------------------------------------
Net revenues 103,429 66,482 35,443
Operating costs 31,488 14,321 9,069
Depreciation, depletion, and amortization 597 887 503
----------------------------------------------------------------------------------------------------------------------
Operating income $ 71,344 $ 51,274 $ 25,871
======================================================================================================================
Other income, net $ 259 $ - $ -
======================================================================================================================
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 $ -
======================================================================================================================
Operating Results - The increase in Marketing and Trading's gross margins on
gas sales in 2001 compared to 2000 is attributable to its ability to capture
higher margins by arbitraging regional price volatility through the use of its
storage and transportation capacity. The Company was also able to capture wider
winter/summer spreads on stored volumes and benefited from falling prices that
positively impacted fuel costs associated with its long-term transportation
contracts while sales volumes decreased slightly. The Company's gross margin
included income recognized from mark-to-market accounting of approximately $35
million and $24 million for 2001 and 2000, respectively. Increased operating
costs are due primarily to increased personnel costs required to operate the
expanded base of marketing and trading activities acquired in 2000. Also, the
Enron bankruptcy resulted in a $22.9 million increase in cost of gas and a
$14.5 million increase in operating costs, totaling a $37.4 million negative
impact on operating results for 2001. The Company's claim against Enron in
bankruptcy is estimated to be $74.0 million.
The increase in gross margins on gas sales in 2000 compared to 1999 is
primarily attributable to the increased volumes achieved through the
acquisition in 2000. The acquisition significantly increased the segment's
commercial control of storage and transportation positions, primarily in the
mid-continent, Rocky Mountain and Texas regions, thereby providing more
leverage for its marketing and trading capabilities. Increased price volatility
during 2000 compared to 1999 also contributed to increased gross margin on gas
sales by providing greater marketing and trading opportunities. Gross margin on
gas sales was also favorably impacted by the change in accounting principle
requiring the Marketing and Trading segment to mark energy trading contracts to
fair value.
Increased operating costs in 2000 compared to 1999 are primarily attributable
to increased personnel costs resulting from the acquisition coupled with
increases in overall personnel to support the expanded base of marketing and
trading activities. Operating costs also increased due to higher costs relating
to technological enhancements necessary to support these activities.
38
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
---------------------------------------------------------------------------
Operating Information
Natural gas volumes (MMcf) 977,602 990,033 389,241
Gross margin ($/Mcf) $ 0.10 $ 0.06 $ 0.08
Capital expenditures (Thousands) $ 1,184 $ 815 $ 448
Total assets (Thousands) $ 1,369,220 $ 3,035,227 $ 269,444
---------------------------------------------------------------------------
Marketing and Trading sales volumes averaged 2.7 Bcf/d in 2001 and 2000 and 1.1
Bcf/d in 1999. The increase in sales volumes compared to 1999 is primarily due
to the acquisition in 2000 and increased trading activity around the Company's
increased storage and transportation capacity. Gross margin per Mcf improved in
2001 compared to 2000 as the Company has now fully integrated its mid-continent
marketing and trading base and is successfully executing its strategies for
transportation and use of storage that focus on capturing higher margin sales.
Gross margin per Mcf decreased in 2000 compared to 1999 as a result of higher
baseload sales resulting from the acquisition of marketing and trading
operations in 2000. The Company has since integrated those acquired contracts
that complement its business strategy while terminating those contracts that do
not.
The decrease in total assets at December 31, 2001 compared to 2000 is primarily
attributable to a decrease of $823.3 million in accounts receivable and a
decrease of $782.4 million in price risk management assets which represent the
fair value of the Company's commodity and derivative trading contracts and
storage inventory. Both were the result of decreased natural gas prices.
The increase in total assets at December 31, 2000, compared to 1999 is
primarily attributable to $1.8 billion in price risk management assets and a
$1.0 billion increase in accounts receivable due to increased marketing and
trading activities and increased natural gas prices.
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 margin 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.
39
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) $ 9 $ 605
Total assets (Thousands) $ 287,375 $ 141,733
----------------------------------------------------------------
Price Risk Management - 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 of Notes to Consolidated Financial Statements.
GATHERING AND PROCESSING
Operational Highlights - The Gathering and Processing segment currently owns
and operates or leases and operates 25 gas processing plants and has an
ownership interest in four additional gas processing plants which it does not
operate. Six operated plants are temporarily idle. The total processing
capacity of plants operated and the Company's proportionate interest in plants
not operated by the Company is 2.2 Bcf/d, of which 0.150 Bcf/d has been idled
temporarily. A total of over 19,300 miles of gathering pipelines support the
gas processing plants.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
------------------------------------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Natural gas liquids and condensate sales $ 587,842 $ 536,470 $ 52,757
Gas sales 635,569 426,364 23,032
Gathering, compression, dehydration and processing fees and other revenues 91,406 73,879 8,001
Cost of Sales 1,125,196 812,701 52,479
------------------------------------------------------------------------------------------------------------------------
Net revenues 189,621 224,012 31,311
Operating costs 116,853 90,501 11,207
Depreciation, depletion, and amortization 29,201 22,692 3,562
------------------------------------------------------------------------------------------------------------------------
Operating income $ 43,567 $ 110,819 $ 16,542
========================================================================================================================
Other income, net $ (178) $ 26,460 $
========================================================================================================================
Operating Results - A full year of operation of assets acquired in early 2000
contributed to increased revenues and cost of sales for 2001 compared to 2000.
However, decreased processing spreads and lower natural gas prices resulted in
lower net revenues for 2001. In the first quarter of 2001, there were negative
processing spreads for the first time in more than 10 years and inter-month
volatility during the year was the greatest it has been at any time during that
same 10-year period. The overall processing spread for 2001 was approximately
75% of the 10-year average of $1.29 per MMBtu. During the year, both crude oil
and natural gas prices fell from $29.33 per barrel and $9.98 per MMBtu to
$18.00 per barrel and $1.83 per MMBtu, respectively. The downturn of the
economy reduced the demand for many NGL products, particularly ethane, which is
a major component of plastic products. Additionally, record high inventories in
natural gas and other petroleum products, such as propane, along with
significantly warmer than normal temperatures across North America during the
heating season lowered demand for natural gas, home heating oil and propane
causing weaker than expected prices in 2001.
40
Increased operating costs and depreciation, depletion, and amortization were
also the result of a full year of operation for the assets acquired.
Net revenues increased in 2000 compared to 1999 due to the assets acquired in
early 2000 and a full year of operation of assets acquired in early 1999. The
average NGL price per gallon increased significantly in 2000. Fee-based
revenues increased in 2000 compared to 1999 as a result of the acquisitions in
2000.
Operating costs and depreciation, depletion and amortization increased for 2000
compared to 1999 as a result of the 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 acquisitions and additional lease expense resulting from the
Bushton lease, which was acquired from KMI in 2000. Other income for 2000
consists of the gain on the sale of the Company's interest in the Indian Basin
processing plant.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
------------------------------------------------------------------------------------------
Gas Processing Plants Operating Information
Total gas gathered (MMMBtu/D) 1,572 1,329 229
Total gas processed (MMMBtu/D) 1,420 1,206 187
Natural gas liquids sales (MBbls) 27,719 23,984 4,559
Natural gas liquids produced (Bbls/d) 74,238 68,999 7,642
Gas sales (MMBtu) 142,828 115,180 10,534
Capital expenditures (Thousands) $ 51,442 $ 32,383 $ 8,557
Total assets (Thousands) $ 1,322,438 $ 1,507,546 $ 343,133
------------------------------------------------------------------------------------------
Volumes of natural gas gathered and processed, NGL sales, NGLs produced and gas
sales increased for 2001 compared to 2000 primarily due to a full year of
operations of the assets acquired in 2000, which provided increased processing
and fractionation capacity. Average NGL prices for 2001 decreased compared to
2000, which offset the impact of the increased volumes. The Conway OPIS
composite NGL price based on the Company's NGL product mix for 2001 decreased
12 percent from $0.531/gal to $0.465/gal. Average natural gas prices increased
for the same period despite decreases during the last half of 2001. The gas
price for the mid-continent region increased 11 percent in 2001 from an average
of $3.74/MMBtu to an average of $4.15/MMBtu.
For 2000, the increase over 1999 for total gas gathered, gas processed, NGL
sales, NGLs produced and gas sales is primarily due to the acquisitions in
early 2000 and a full year of operations from the acquisition in April 1999.
The increase in capital expenditures from 2000 to 2001 and from 1999 to 2000 is
primarily due to the acquisitions. Additional increases in 2000 and 2001 are
related to the Company consolidating its plants in Texas to lower operating
costs and optimize recoveries.
The decrease in total assets from 2000 to 2001 is due to decreases in cash and
accounts receivable due to decreased prices. The increase in total assets from
1999 to 2000 is primarily attributable to a $619.3 million increase in
property, plant and equipment acquired in the 2000 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, 2001, the Gathering and Processing segment
had a portion of its natural gas costs and NGL production hedged. The Company
also used derivative instruments during 2001 to minimize risk associated with
price volatility and expects to utilize such instruments during 2002. See Item
7A - Quantitative and Qualitative Disclosures About Market Risk and Note C of
Notes to Consolidated Financial Statements.
41
Transition Period Operating Results
Four Months Ended
December 31,
1999 1998
--------------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Natural gas liquids and condensate sales $ 43,290 $ 8,951
Gas sales 28,824 4,157
Gathering, compression, dehydration and processing fees and other revenues 6,787 1,398
Cost of sales 59,488 8,388
--------------------------------------------------------------------------------------------------
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 in
April 1999. Operating costs and depreciation also increased due to the
additional assets and the cost of operating those assets. 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.
Four Months Ended
December 31,
1999 1998
----------------------------------------------------------------------
Gas Processing Plants Operating Information
Total gas gathered (MMMBtu/D) 481 127
Total gas processed (MMMBtu/D) 397 115
Natural gas liquids sales (MBbls) 3,007 927
Natural gas liquids produced (Bbls/d) 7,022 7,642
Gas sales (MMBtu) 10,643 2,303
Capital expenditures (Thousands) $ 14,613 $ 974
Total assets (Thousands) $ 368,904 $45,709
----------------------------------------------------------------------
TRANSPORTATION AND STORAGE
Operational Highlights - The Transportation and Storage segment represents the
Company's intrastate transmission pipelines and natural gas storage facilities.
The Company has five storage facilities in Oklahoma, two in Kansas and three in
Texas with a combined working capacity of approximately 58 Bcf, of which 8 Bcf
is idled. The Company's intrastate transmission pipelines operate in Oklahoma,
Kansas and Texas and are regulated by the OCC, KCC and TRC, respectively.
42
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
--------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Transportation revenues $ 117,999 $ 94,112 $ 78,720
Storage revenues 37,645 38,464 27,763
Gas sales and other revenues 23,326 35,882 1,402
Cost of fuel and gas 49,626 42,876 4,975
--------------------------------------------------------------------------------------
Net revenues 129,344 125,582 102,910
Operating costs 52,497 44,785 28,919
Depreciation, depletion, and amortization 19,190 18,639 13,852
--------------------------------------------------------------------------------------
Operating income $ 57,657 $ 62,158 $ 60,139
======================================================================================
Other income, net $ 2,578 $ 3,240 $ 6,495
======================================================================================
Operating results -Transportation revenues increased for 2001 compared to 2000
due to higher retained fuel from a full year of operation of assets acquired in
early 2000. This increase was partially offset by a reduction in volumes
transported associated with reduced demand for irrigation due to higher natural
gas prices, making gas-powered irrigation uneconomical for many farmers, and
warmer than normal temperatures during the fourth quarter of 2001. The
expiration of gas sales contracts acquired in early 2000 resulted in a decrease
of $4.6 million in gas sales revenue in 2001. While revenues from unaffiliated
companies decreased as gas sales contracts expired, revenues from
transportation contracts replaced the margin generated by those expired gas
sales contracts. The increase in cost of fuel in 2001 compared to 2000 is due
to a full year of operation of the assets acquired in 2000 and increased gas
prices.
Operating costs increased due to higher ad valorem taxes, labor and other
operating costs associated with a full year of operation of the assets acquired
in 2000. Depreciation, depletion and amortization also increased in 2001 due to
the 2000 acquisitions.
For 2000 compared to 1999, transportation revenues increased due to higher
retained fuel despite reduced tariff rates paid by an affiliate for
transportation services. Storage revenues increased due to increased capacity
of approximately 10 Bcf resulting from the acquisition of storage facilities in
2000. 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 lower than in prior years. Gas
sales and other revenues and cost of gas increased due to gas sales contracts
acquired in 2000 and leasing fees related to a pipeline acquired in 2000.
Operating costs and depreciation, depletion, and amortization increased in 2000
compared to 1999 primarily as a result of increased plant operating costs and
personnel costs resulting from acquisitions.
Other income, net represents income from equity investments in Potato Hills and
Sycamore Gathering. In 1999, approximately $5.0 million of gains on sales of
assets were also included.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
--------------------------------------------------------------------------
Operating Information
Volumes transported (MMcf) 538,221 557,052 348,397
Capital expenditures (Thousands) $ 35,911 $ 37,701 $ 32,618
Total assets (Thousands) $ 797,331 $ 661,894 $ 373,742
--------------------------------------------------------------------------
Volumes of natural gas transported decreased in 2001 due a return to normal
weather as compared to 2000. This decrease was partially offset by an increase
in volumes transported due to operating the assets acquired in 2000 for a full
year. The increase in volumes transported in 2000 compared to 1999 was
primarily driven by the acquisitions in 2000 and colder weather.
43
Total assets increased in 2001 due to increases in cash and accounts
receivables. Total assets increased in 2000 due to increases in property, plant
and equipment and in accounts receivable primarily due to the acquisitions.
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 OCC Order, the Company's gathering and storage assets and related services
in Oklahoma were removed from utility regulation effective November 1, 1999
resulting in gathering and storage assets being removed from rate base. ONG
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 retained 96 percent of ONG's transportation services. With
unbundling of transportation services and deregulation of gathering and
storage, the Company is now competing for business at market-based rates.
During 2001, an OCC cause related to an affiliate, ONG, also involved the
Marketing and Trading segment and the Transportation and Storage segment. In
this cause, Enogex, Inc. requested a rebid of gas supply and transportation
service. If OEMT had lost the gas supply bid previously awarded, OEMT would no
longer need companies in the Transportation and Storage segment to transport
the gas supply. The OCC declined to order a rebid.
An application has been filed with the KCC requesting approval to transfer a
portion of the transportation assets in the Market Center to KGS. The operation
of these assets is regulated by the KCC. The Market Center transportation
system provides access to the major natural gas producing areas in Kansas
intersecting with nine intra/interstate pipelines at 18 interconnect points,
four processing plants, and approximately three producing fields effectively
allowing gas to be moved throughout the state. With the transfer of these
assets, KGS will be able to provide itself with firm transportation service.
Transition Period Operating Results
Four Months Ended
December 31,
1999 1998
-----------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Transportation revenues $ 24,733 $ 25,956
Storage revenues 14,171 9,099
Gas sales and other revenues 247 942
Cost of fuel and gas 4,660 2,047
-----------------------------------------------------------------------
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
=======================================================================
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.
44
Four Months Ended,
December 31,
1999 1998
--------------------------------------------------------------
Operating Information
Volumes transported (MMcf) 117,055 115,970
Capital expenditures (Thousands) $ 5,837 $ 13,163
Total assets (Thousands) $ 437,561 $ 507,573
--------------------------------------------------------------
DISTRIBUTION
Operational Highlights - 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 the
population of Oklahoma and about 71 percent of the population of Kansas. ONG
and KGS are subject to regulatory oversight by the OCC and KCC, respectively.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
-------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Gas sales $ 1,434,184 $ 1,198,604 $ 848,813
Cost of gas 1,157,575 896,660 530,489
-------------------------------------------------------------------------------------------
Gross margin 276,609 301,944 318,324
PCL and ECT Revenues 55,206 59,205 58,037
Other revenues 21,578 16,128 17,100
-------------------------------------------------------------------------------------------
Net revenues 353,393 377,277 393,461
Operating costs 230,137 211,629 219,945
Depreciation, depletion, and amortization 69,159 67,717 75,443
-------------------------------------------------------------------------------------------
Operating income $ 54,097 $ 97,931 $ 98,073
===========================================================================================
Other income, net $ (946) $ - $ -
===========================================================================================
Operating Results - Gas sales and cost of gas increased in 2001 compared to
2000 due to a higher weighted average cost of gas. Although prices of natural
gas decreased in the latter part of 2001 from their historically high levels
during the winter of 2000/2001, those costs were still billed and recovered
throughout most of 2001. Since gas costs are recognized as they are recovered
from the ratepayer, the mechanism providing recovery of gas costs and
regulatory actions in Oklahoma delayed much of the recovery of high gas costs
in late 2000 until 2001 and, accordingly, delayed recognition of the costs.
In the fourth quarter of 2001, the Company recorded a $34.6 million charge to
cost of gas as a result of the OCC's order limiting ONG's recovery of gas
purchase expense related to the 2000/2001 winter. This resulted in a decrease
in gross margin on gas sales in 2001 compared to 2000. KGS gross margin
increased $3.0 million in 2001 over 2000 due to impact of the Weather
Normalization Program offsetting the warmer weather. ECT revenues decreased
$3.4 million in 2001 from 2000 due largely to lower volumes delivered to
electric generation customers due to milder summer weather.
Gross margin on gas sales decreased in 2000 compared to fiscal 1999, primarily
due to warmer weather in Kansas which impacted margins by $15.4 million 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 $5.3 million resulting from
additional "As Available" gas sales.
45
Operating cost for 2001 increased over 2000 due to additional bad debt expense
of $19.2 million incurred as a result of the increased natural gas prices
during the winter of 2000/2001. This was partially offset by a reduction in
operating costs due to the continuation of a successful cost containment
program.
The decrease in operating costs in 2000 compared to 1999 resulted from a cost
containment program and decreased 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
that reduced depreciation expense and revenues by approximately $10.5 million
annually for Oklahoma assets and transferred certain transportation assets from
the Distribution segment to the Transportation and Storage segment. The same
order directed ONG to assume responsibility for certain customer service lines
and allowed ONG to defer the costs associated with the service lines until
addressed in the next rate case filing.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
--------------------------------------------------------------
Gross Margin per Mcf
Oklahoma
Residential $2.71 $2.76 $3.04
Commercial $2.18 $1.97 $2.47
Industrial $1.34 $1.09 $1.23
Pipeline capacity leases $0.30 $0.27 $0.25
Kansas
Residential $2.45 $2.44 $2.44
Commercial $1.82 $1.91 $1.81
Industrial $1.43 $1.85 $2.28
End-use customer transportation $0.61 $0.63 $0.49
--------------------------------------------------------------
The decrease in Kansas' commercial and industrial gross margins per Mcf for
2001 from 2000 results from the full year impact of the tariff rate reduction
that took effect in July 2000. Oklahoma's gross margin per Mcf increased for
commercial and industrial due to adjustments to gas purchase expense and a
deferral of revenues from a line loss rider from 2000 to 2001. A full year of
tariff rate reductions in 2001 partially offset this increase and resulted in a
decrease to gross margin per Mcf for residential.
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.
46
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
---------------------------------------------------------------------------------------
Operating Information
Average Number of Customers
Oklahoma 794,008 784,746 748,445
Kansas 642,436 633,698 656,761
---------------------------------------------------------------------------------------
Total 1,436,444 1,418,444 1,405,206
=======================================================================================
Customers per employee
Oklahoma 639 586 546
Kansas 579 555 510
=======================================================================================
Capital Expenditures (Thousands) $ 129,937 $ 124,983 $ 98,685
=======================================================================================
Total Assets (Thousands) $ 1,688,670 $ 2,007,351 $ 1,722,381
=======================================================================================
The consolidation of the KGS-Oklahoma regulated service with ONG in 2000
resulted in the transfer of approximately 35,000 customers from Kansas to
Oklahoma.
The Company's capital expenditure program includes expenditures for extending
service to new areas, modifying customer service lines, 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
$22.4 million, $21.4 million, and $19.8 million for new business development in
2001, 2000, and 1999, respectively.
Years Ended Year ended
December 31, August 31,
2001 2000 1999
---------------------------------------------------------------------
Volumes (MMcf)
Gas sales
Residential 102,976 107,154 105,566
Commercial 40,578 40,713 41,398
Industrial 4,101 5,582 5,575
Wholesale 31,060 34,781 34,846
---------------------------------------------------------------------
Total volumes sold 178,715 188,230 187,385
PCL and ECT 136,975 158,100 177,701
---------------------------------------------------------------------
Total volumes delivered 315,690 346,330 365,086
====================================================================
The decrease in volumes sold is due to warmer weather in 2001 compared to 2000
and, for industrial and wholesale sales, the movement of some customers to the
PCL program.
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 and early 2001 due to historically high
natural gas prices. 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 customers to be added to the
customer base.
Regulatory Initiatives -The extraordinarily cold winter of 2000/2001 produced a
number of regulatory initiatives. The OCC issued an order denying ONG the right
to collect $34.6 million in outstanding gas costs incurred while serving
customers during the 2000/2001 winter season. The Company appealed this order
to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this
order pending the outcome of the Company's appeal. The OCC subsequently
approved the Company's request to stay this order allowing ONG to collect the
$34.6 million, subject to refund should the Company ultimately lose the case.
ONEOK took a charge against fourth-quarter earnings as a result of the
Commission's order. Although the Company will continue to assert its legal
rights, it is hopeful that a resolution of this issue can be negotiated.
47
ONG continues to take an active role in response to the OCC's Notice of Inquiry
regarding the use of physical and financial instruments to hedge against fuel
procurement volatility. ONG exercised provisions contained in a number of its
gas supply contracts that allow the Company to fix the price of a portion of
its gas supply. ONG fixed the price of approximately 40% of its anticipated
2001/2002 winter gas supply deliveries.
The Company received approval from the OCC to create a Voluntary Fixed Price
pilot program that will enable its general sales customers to fix the gas cost
portion of their bill for a specified winter period. The program is being
initiated as a means of providing customers with a means of controlling their
2002/2003 gas bills.
During 2001, the KCC issued an Order extending the time period for which gas
service disconnection during inclement weather conditions cannot be made. Due
to the extension of the time period restricting disconnections, delinquent KGS
customers were allowed to continue gas service, thus increasing uncollectible
amounts. Higher gas costs in the 2000/2001 heating season also contributed to
the increased uncollectible amounts. KGS and other distribution companies in
Kansas filed a joint application with the KCC seeking approval to recover the
additional uncollectible amounts incurred during the 2000/2001 heating season
until reviewed in the next rate case. The KCC approved the deferral allowing
the companies to seek recovery of the extraordinary uncollectible account
levels experienced in the 2000/2001 winter. KGS expects to file a rate case in
late 2002. No accounting treatment has yet been determined.
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 approved KGS's WeatherProof Bill Program
that had been a temporary program. This plan allows customers, at their
discretion, to fix their monthly payment. The KCC also granted KGS weather
normalization in December 2000 that prevents weather related revenue
fluctuations.
Transition Period Operating Results
Four Months Ended
December 31,
1999 1998
----------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Gas sales $ 316,901 $ 286,317
Cost of gas 209,354 180,795
----------------------------------------------------------------------------
Gross margin 107,547 105,522
PCL and ECT revenues 18,230 19,582
Other revenues 4,093 4,554
----------------------------------------------------------------------------
Net revenues 129,870 129,658
Operating costs 69,455 73,004
Depreciation, depletion, and amortization 24,815 24,603
----------------------------------------------------------------------------
Operating income $ 35,600 $ 32,051
============================================================================
Gross margins on gas sales increased primarily due to reduced transportation
costs paid to an affiliate. 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.
48
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
Customers per employee 546 527
Capital expenditures (Thousands) $ 34,167 $ 24,636
Total assets (Thousands) $ 1,776,273 $ 1,804,631
---------------------------------------------------------------
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
Wholesale 12,062 13,150
---------------------------------------------------------------
Total volumes sold 57,180 58,083
PCL and ECT 49,634 63,824
---------------------------------------------------------------
Total volumes delivered 106,814 121,907
===============================================================
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" (Statement 71). Total regulatory assets resulting from this
deferral process are approximately $222.4 million for the Distribution segment.
Although no further unbundling of services is anticipated, should this occur,
certain of these assets may no longer meet the criteria for following Statement
71, and accordingly, a write-off of regulatory assets and stranded costs may be
required.
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. The Company continually focuses on reducing finding
costs and minimizing production costs.
49
During 2001, the Company acquired approximately $1.5 million in gas and oil
properties. Through the Company's developmental drilling program, 155 wells
were drilled during 2001 compared to 103 wells completed in 2000, an increase
of more than 50 percent.
Risk Management - The volatility of energy prices has a significant impact on
the profitability of this segment As of December 31, 2001, 11 percent of
anticipated 2002 proved developed producing well volumes, totaling
approximately 2.3 Bcf, was hedged at an average price of $3.17 per Mcf. In
2001, 74 percent of proved developed producing well volumes, totaling
approximately 17 Bcf, was hedged at an average price of $3.60 per Mcf. See Item
7A - Quantitative and Qualitative Disclosure about Market Risk and Note C of
Notes to the Consolidated Financial Statements.
Years Ended Years Ended
December 31, August 31,
2001 2000 1999
-----------------------------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Natural gas sales $ 107,846 $ 60,966 $ 58,776
Oil sales 12,262 8,571 6,169
Other revenues 209 818 1,949
------------------------------------------------------------------------------------------------------------------
Net revenues 120,317 70,355 66,894
Operating costs 27,361 24,228 19,128
Depreciation, depletion, and amortization 35,017 30,884 34,073
------------------------------------------------------------------------------------------------------------------
Operating income $ 57,939 $ 15,243 $ 13,693
==================================================================================================================
Other income, net $ 1,175 $ 545 $ 1,704
==================================================================================================================
Cumulative effect of a change in accounting principle $ (3,508) $ - $ -
Income tax 1,357 - -
------------------------------------------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle, net of tax $ (2,151) $ - $ -
==================================================================================================================
Operating Results - Net revenues increased significantly in 2001 compared to
2000 due to higher average gas prices for 2001, particularly during the first
half of the year. The Company also benefited from higher oil and gas production
in 2001 compared to 2000. Operating costs increased in 2001 due to higher
production taxes resulting from higher oil and gas revenues. Depreciation,
depletion and amortization increased in 2001 compared to 2000 due primarily
from higher production, along with a slightly higher depletion rate.
Net revenues increased in 2000 compared to 1999, due to higher natural gas and
oil prices. The Company hedged the majority of its production in 2000. The
impact of slightly higher commodity prices realized by the Company on revenues
was partially offset by natural declines in production that was not replaced by
new production.
Operating costs increased in 2000 as compared with 1999 as a result of higher
production taxes. 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 in 2001 primarily represents the gain from the sale of the
Company's 40 percent interest in K. Stewart.
50
Years Ended Years Ended
December 31, August 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------------------------------
Operating Information
Proved reserves
Gas (MMcf) 232,967 254,721 254,102
Oil (MBbls) 4,511 4,339 4,197
Production
Gas (MMcf) 27,578 26,746 27,773
Oil (MBbls) 493 400 460
Average realized price (a)
Gas (Mcf) $ 3.91 $ 2.28 $ 2.12
Oil (Bbls) $ 24.89 $ 21.43 $ 13.56
Capital expenditures (Thousands) $ 55,974 $ 34,035 $ 16,046
Total assets (Thousands) $ 321,720 $ 308,041 $ 310,715
----------------------------------------------------------------------------------------------------------------------------------
(a) The average realized price, above, reflects the impact of hedging activities.
The Production segment added 9.8 Bcfe of net reserves in 2001 after
adjustments, including 20.8 Bcfe proved developed, 8.0 Bcfe proved behind pipe,
12.5 Bcfe proved undeveloped, offset by 31.5 Bcfe of downward revisions of
proved reserve due to lower year-end 2001 prices and the resulting shorter
economic life of some wells and the reduction of proved undeveloped reserve
estimates as they were converted to proved developed reserves. Production for
the year ended December 31, 2001 was 30.5 Bcfe.
Capital expenditures above primarily relate to the drilling program, which
consisted of drilling costs of approximately $53.2 million, $32.8 million, and
$13.7 million in 2001, 2000, and 1999, respectively.
Transition Period Operating Results
Four Months Ended
December 31,
1999 1998
--------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
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 $ (11) $ -
==========================================================================
51
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.
Operating costs also increased, compared to 1998, due to the Company operating
and owning an interest in an increased number of wells.
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 (a)
Gas (Mcf) $ 2.50 $ 2.03
Oil (Bbls) $ 18.93 $ 12.53
Capital expenditures (Thousands) $ 6,411 $ 4,581
Total assets (Thousands) $ 301,821 $ 275,840
==============================================================================
(a) The average realized price, above, reflects the impact of hedging
activities.
POWER
Operational Highlights - The Company created the Power segment in January 2001
to include the operating results of the electric generating plant constructed
by the Company. The 300-megawatt electric power plant is located adjacent to
one of the Company's natural gas storage facilities and is configured to supply
electric power during peak periods with four gas-powered turbine generators
manufactured by General Electric. The Company's strategy is to capture the
value added by converting natural gas to electricity, the spark spread premium,
during peak demand periods. The plant began operations in mid-2001. The
construction of this power plant complements the Company's strategy of
maximizing earnings capacity of existing assets and exploring new opportunities
that are expected to have a positive impact on earnings.
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
--------------------------------------------------------------------------------------------
Financial Results (Thousands of Dollars)
Power sales $ 28,092 $ - $ -
Cost of power 21,234 - -
--------------------------------------------------------------------------------------------
Gross margin on power sales 6,858 - -
Operating costs 1,358 - -
Depreciation, depletion, and amortization 2,014 - -
--------------------------------------------------------------------------------------------
Operating income $ 3,486 $ - $ -
============================================================================================
Other income, net $ (6) $ - $ -
============================================================================================
Operating Results - Power sales consist primarily of peaking sales rather than
baseload contracts. Gross margin on power sales for 2001 were less than that
which would be expected had the plant been in operation for a full year. Cooler
weather during the summer of 2001 and low power prices both negatively impacted
gross margins. The majority of the cost of power is generated by the peaking
plant rather than purchased from unaffiliated companies.
52
Years Ended Year Ended
December 31, August 31,
2001 2000 1999
-------------------------------------------------------------------------
Operating Information
Power volumes (MMwh) 467 - -
Gross margin ($/MMwh ) $ 14.69 $ - $ -
Capital expenditures (Thousands) $ 42,302 $ 58,697 $ 3,748
Total assets (Thousands) $ 122,404 $ 77,426 $ 4,047
-------------------------------------------------------------------------
Prior to January 1, 2001, capital expenditures for the construction of the peak
electric generating plant had been included in the Marketing and Trading
segment. These capital expenditures have been reclassified and included in the
Power segment for the periods shown in this report. Capital expenditures for
the four months ended December 31, 1999 were $13.4 million. Primarily all
capital expenditures incurred through 2001 relate to the construction of the
plant.
Price Risk Management - The Company's strategy is to capture market volatility
in the spark spread premium. In doing so, the Power segment 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
of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
A part of the Company's strategy has been and continues to be growth through
acquisitions that strengthen and complement existing assets. The Company
anticipates capital expenditures for 2002, exclusive of any acquisitions that
may be made, to be approximately $242 million, which is less than previous
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 capital markets 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.
Financing is provided through the Company's commercial paper program, long-term
debt and, if needed, through a revolving credit facility. Other options to
obtain financing include, but are not limited to, issuance of equity, asset
securitization and sale/leaseback of facilities. The Company currently has a
$500 million shelf registration in effect covering debt securities, including
convertible debt and common stock. During 2001, capital expenditures were
financed through operating cash flows and long-term debt.
The Company's credit rating may be affected by a material change in financial
ratios or a material adverse event. The most common criteria for assessment of
the Company's credit rating are the debt to capital ratio, pre-tax and
after-tax interest coverage and liquidity. If the Company's credit rating were
downgraded, the interest rates on the commercial paper would increase,
therefore, increasing the Company's cost to borrow funds. In the event, that
the Company was unable to borrow funds under the commercial paper program, the
Company has access to an $850 million revolving credit facility. In addition,
downgrades in the Company's credit rating could impact the Marketing and
Trading segment's ability to do business by requiring the Company to post
margins with the few counterparties with which the Company has a Credit Support
Annex within its International Swaps and Derivatives Association Agreement.
53
The Company has reviewed its commercial paper agreement, trust indentures,
building leases, Bushton equipment leases, and marketing, trading and risk
contracts and no rating triggers were identified. Rating triggers are defined
as provisions that would create an automatic default or acceleration of
indebtedness based on a change in the Company's credit rating. The revolving
credit agreement does contain a provision that would cause the cost to borrow
funds to increase based on the amount borrowed under this agreement if the
Company's credit rating is negatively adjusted. This credit agreement also
contains a default provision based on a material adverse change of the Company,
but an adverse rating change is not defined as a default or material adverse
change. The Company currently does not borrow funds under this agreement. The
Company also has no guarantees of debt or other commitments to unaffiliated
parties.
The OCC staff filed an application on February 1, 2001 to review the gas
procurement practices of ONG in acquiring its gas supply for the 2000/2001
heating season to determine if they were consistent with least cost procurement
practices and whether the Company's decisions resulted in fair, just and
reasonable costs being borne by its customers. An order issued on November 20,
2001 denied the recovery of a portion of the Company's unrecovered purchased
gas cost account related to the unrecovered gas costs from the 2000/2001 winter
effective December 1, 2001, leaving ONG with an estimated $34.6 million in
unrecovered gas costs . The Company appealed this order to the Oklahoma Supreme
Court and asked the OCC to stay the provisions of this order pending the
outcome of the Company's appeal. The OCC subsequently approved the Company's
request to stay the order. The stay allows ONG to continue recovery of this
$34.6 million in gas costs subject to refund if the Oklahoma Supreme Court
ultimately rules against the Company. The Company believes that decisions made
by the Company were prudent based upon the facts and circumstances existing at
the time the decisions were made, which is the standard applicable to the
proceeding as stated by the OCC. The Company will defend itself vigorously;
however, the Company has taken a charge of $34.6 million in the fourth quarter
of 2001 as a result of this order. This charge is recorded as an increase in
gas purchase expense in the Distribution segment.
During 2001, the Company put in place a stock buyback plan for up to 10 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. 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. At December 31, 2001, the
Company had not purchased any stock under the plan.
The Company is subject to commodity price volatility. Significant fluctuations
in commodity price in either physical or financial energy contracts may impact
the Company's overall liquidity due to the impact the commodity price change
has on items such as the cost of gas held in storage, recoverability and timing
of regulated natural gas costs, increased margin requirements, collectibility
of certain energy related receivables and working capital. The Company believes
that its current commercial paper program and debt capacity is adequate to meet
liquidity requirements from commodity price volatility.
CASH FLOW ANALYSIS
Operating Cash Flows - In 2001, the changes in cash flows provided by operating
activities primarily reflect changes in working capital accounts, deferred
income taxes and price risk management assets and liabilities. The increase in
deferred income taxes, a non-cash item, is due to accelerated depreciation in
2001. The increase in price risk management assets and liabilities is primarily
due to $35 million in mark-to-market income, which is a non-cash item, and an
increase in the Marketing and Trading segment's gas in storage, which is
included in price risk management assets on the consolidated balance sheet. The
level of gas held in storage is higher at December 31, 2001 compared to
December 31, 2000 due to warmer weather in 2001. Cash flow from operating
activities was positively impacted in the current year due to the reduction of
accounts receivable, which was partially offset by increased cash used for
payment of accounts payable and gas in storage and reduced recovery of
unrecovered purchased gas costs. Receivables and payables were higher than
normal at December 31, 2000, due to higher gas prices and the integration of
the businesses acquired in 2000.
54
In 2000, the changes in cash flow provided by operating activities primarily
reflect changes in working capital accounts and an increase in assets and
liabilities in 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 in 2000 and historically higher gas prices. The increase in price
risk management activities is due to the adoption of mark-to-market accounting
in 2000.
Investing Cash Flows - Cash paid for capital expenditures for the year ended
December 31, 2001 was $341.6 million. This includes approximately $42.3 million
for the construction of the electric generating plant. For the year ended
December 31, 2000, capital expenditures were $311.4 million, which included
$58.7 million for the construction of the electric generating plant. In 2001,
the Company was reimbursed by an unaffiliated company for approximately $14
million of the costs incurred to construct a pipeline in the Transportation and
Storage segment. Due to regulatory treatment, this amount is recorded as a
deferred credit in the balance sheet and amortized to income. The Company also
received approximately $7.9 million related to the sale of assets in the
Production segment. Acquisitions in 2001 include $14.5 million of purchase
price adjustments, which resulted in an increase to goodwill adjustments,
relating to the Kinder Morgan acquisitions. The increase in capital
expenditures for the year ended December 31, 2001 compared to the same period
one year ago is primarily attributable to increased costs of sustaining a
higher asset base due to the acquisitions in 2000.
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.
Financing Cash Flows - The Company's capitalization structure is 42 percent
equity and 58 percent long-term debt at December 31, 2001, compared to 48
percent equity and 52 percent long-term debt at December 31, 2000. At December
31, 2001, $1.7 billion of long-term debt was outstanding. As of that date, the
Company could have issued $1,064.5 million of additional long-term debt under
the most restrictive provisions contained in its various borrowing agreements.
The Board of Directors has authorized up to $1.2 billion of short term
financing to be procured as necessary for the operation of the Company. The
Company has an $850 million Revolving Credit Facility with Bank of America,
N.A. and other financial institutions with a maturity date of June 27, 2002.
This credit facility is primarily used to support the commercial paper program.
At December 31, 2001, $599 million of commercial paper was outstanding, which
includes approximately $28 million of temporary investments and $275 million
used to purchase natural gas that was injected into storage. At March 8, 2002,
$413 million of commercial paper was outstanding, which includes approximately
$118 million of temporary investments and $165 million used to purchase natural
gas that was injected in to storage.
In April 2001, the Company issued a $400 million, ten year, fixed rate note
to refinance short-term debt. In July 2001, the Company entered into interest
rate swaps on this debt with a term equal to the term of the notes. The
interest rate under these swaps resets periodically based on the three-month
London InterBank Offered Rate (LIBOR) or the six-month LIBOR at the reset date.
In October 2001, the Company entered into an agreement to lock in the interest
rates for each reset period under the swap agreements through the first quarter
of 2003. In December 2001, the Company entered into interest rate swaps on a
total of $200 million in fixed rate long-term debt through the term of the
note. The interest rate under these swaps resets periodically based on the
six-month LIBOR at the reset date. The average interest rate of the $600
million in notes is 6.971 percent. Under the current swap agreements, the
average interest rate of the notes is an all-in LIBOR rate of approximately
3.516 percent. The all-in LIBOR rate refers to the average LIBOR rate plus or
minus the ONEOK basis spread for all swaps. The swaps resulted in approximately
$5.3 million of interest rate savings in 2001.
55
On July 18, 2001, the Company filed a "shelf" registration statement on Form
S-3 pursuant to which the Company may offer debt securities and shares of the
Company's common stock in one or more offerings with a total initial offering
price of up to $500 million. On December 28, 2001, the Company filed a
Post-Effective Amendment with the intent to allow the Company to offer
convertible debt under this existing shelf registration.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table discloses the Company's contractual obligations to make
future payments under the Company's current debt agreements, operating lease
agreements and fixed price contracts. For further discussion of the debt and
operating lease agreements, see Notes I and K, respectively, of Notes to the
Consolidated Financial Statements.
Payments Due by Period
--------------------------------------------------------------------------------
Contractual Obligations Total 2002 2003 2004 2005 2006 Thereafter
----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Long-term debt $ 1,744,160 $ 250,000 $ 10,000 $ 50,000 $ 360,000 $ 310,000 $ 764,160
Notes payable 599,106 599,106 - - - - -
Operating leases 284,821 33,042 25,137 24,567 27,372 40,683 134,020
Storage contracts 32,039 15,433 6,282 3,236 3,150 3,150 788
Firm transportation contracts 39,657 11,717 5,916 4,502 3,872 3,470 10,180
Purchase commitments,
rights-of-way and other 15,788 3,190 2,711 2,642 2,597 2,475 2,173
----------------------------------------------------------------------------------------------------------------
Total Contractual Obligations $ 2,715,571 $ 912,488 $ 50,046 $ 84,947 $ 396,991 $ 359,778 $ 911,321
================================================================================================================
Long-term debt as reported in the consolidated balance sheets includes
unamortized debt discount and the mark-to-market effect of interest rate swaps.
Operating leases and purchase commitments, rights-of-way and other included
approximately $0.9 million and $1.7 million for 2007, respectively, of annual
commitments but are not included in the above table beyond 2007 due to the
impracticality of calculating the future commitment. The Distribution segment is
party to fixed price transportation contracts; however, the costs associated
with these contracts are recovered through rates as allowed by the applicable
regulatory agency and are excluded from the above table.
TRADING ACTIVITIES
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 amounts include the cost of gas in storage, option premiums and the
mark to market component (fair value).
The following is a detail of the fair value component of the price risk
management assets and liabilities, which result from the Marketing and Trading
segment's energy trading portfolio.
------------------------------------------------------------------------------
(Thousands of Dollars)
Net fair value of contracts outstanding at December 31, 2000 $ 24,219
Contracts realized or otherwise settled during the period (28,580)
Fair value of new contracts when entered into during the period 81,026
Changes in fair values attributable to changes in
valuation techniques and assumptions -
Other changes in fair value (1) (17,053)
------------------------------------------------------------------------------
Net fair value of contracts outstanding at December 31, 2001 $ 59,612
==============================================================================
(1) Other changes in fair value primarily relate to a charge to expense for
unrealized gains associated with swaps and options with Enron as a result
of Enron's bankruptcy filing.
56
The net fair value of contracts outstanding at December 31, 2001 includes energy
trading contracts accounted for under mark-to-market accounting. The net fair
value of contracts outstanding includes the effect of settled energy contracts
and current period charges resulting primarily from newly originated
transactions and the impact of price movements on the fair value of price risk
management assets and liabilities attributable to the Marketing and Trading
segment's activities.
The following is a detail of the Marketing and Trading segment's maturity of
energy trading contracts based on heating injection and withdrawal periods from
April through March. This maturity schedule is consistent with the Marketing and
Trading segment's trading strategy. The Marketing and Trading segment has
contracted over 40 Bcf of storage with an affiliate, which is excluded from
outstanding fair value at December 31, 2001, in accordance with accounting
principles generally accepted in the United States of America.
Fair Value of Contracts at December 31, 2001
--------------------------------------------------------------------------------
Matures Matures Matures Matures Total
through through through after fair
Source of Fair Value March 2003 March 2006 March 2008 March 2008 value
---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Prices actively quoted (1) $ (22,627) $ (1,603) $ - $ - $ (24,230)
Prices provded by other external sources (2) $ 124,474 913 (4,149) (1,567) $ 119,671
Prices based on models and other
valuation models (3) $ (61,564) 30,509 4,065 (8,839) $ (35,829)
---------------------------------------------------------------------------------------------------------------------------------
Total $ 40,283 $ 29,819 $ (84) $ (10,406) $ 59,612
=================================================================================================================================
(1) Prices actively quoted - values are derived from energy market price
quotes from national commodity trading exchanges that primarily trade
future and option commodity contracts.
(2) Prices provided by other external sources - values are obtained through
energy commodity brokers or electronic trading platforms, whose primary
service is to match-up willing buyers and sellers of energy
commodities. Because of the vast energy broker network, energy price
information by location is readily available.
(3) Prices based on models and other valuation models - values include
primarily natural gas storage and transportation capacity contracted by
OEMT. Values derived in this category utilize market price information
from the aforementioned categories as well as other modeling
assumptions that include, among others, assumptions for liquidity,
credit, time value and other external attributes. Values attributable
to storage models are determined on a heating injection/withdraw model.
57
The following table details OEMT's financial and commodity risk from fixed-price
transactions:
Investment Below Investment
Grade Credit Grade Credit
Quality (1) Quality
--------------------------------------------------------------------------------
(Thousands of Dollars)
Gas and electric utilities $ 44,361 $ 1,084
Financial institutions (14,739) -
Oil and gas producers (13,046) (7,044)
Industrial and commercial 12,631 3,819
Other (448) (263)
--------------------------------------------------------------------------------
Total 28,759 (2,404)
Credit and other reserves (320) (755)
--------------------------------------------------------------------------------
Net value of fixed-price transactions $ 28,439 $ (3,159)
================================================================================
(1) Investment grade is primarily determined using publicly available credit
ratings along with consideration of cash prepayments, cash managing, standby
letters of credit and parent company guarantees. Included in Investment Grade
are counterparties with a minimum Standard and Poor's or Moody's rating of
BBB- or Baa3, respectively.
Related Party Transactions - KGS has a shared service agreement with Western,
which is the holder of the Company's preferred stock. The shared services
include call center backup, meter readings, customer billing operations and
customer service. KGS paid Western approximately $4.9 million in 2001 related
to this shared service agreement.
Off-Balance Sheet Arrangements - The Company has no off-balance sheet special
purpose entities or asset securitization.
Enron - Certain of the financial instruments discussed in Note C of Notes to
the Consolidated Financial Statements have Enron North America as the
counterparty. Enron Corporation and various subsidiaries, including Enron
North America (Enron), filed for protection from creditors under Chapter 11 of
the United States Bankruptcy Code on December 3, 2001. The Company has provided
an allowance for forward financial positions and also established an allowance
for uncollectible accounts relating to previously settled financial and
physical positions with Enron at December 31, 2001. The Company estimates its
claim against Enron to be approximately $74 million. Although the ultimate
resolution of any claims ONEOK may have against Enron cannot be determined at
this time, the Company believes any future losses would have an immaterial
effect on the Company's financial position, cash flows and results of
operations.
The filing of the voluntary bankruptcy proceeding by Enron created a possible
technical default related to various financing leases tied to the Company's
Bushton gas processing plant in south central Kansas. The Company acquired the
Bushton gas processing plant and related leases from Kinder Morgan in April
2000. Kinder Morgan had previously acquired the plant and leases from Enron.
Enron is one of three guarantors of these Bushton plant leases; however, the
Company is the primary guarantor. In January 2002, the Company was granted a
waiver on the possible technical default related to these leases. The Company
will continue to make all payments due under these leases.
58
Uncollectible Amounts - During 2001, the KCC issued an Order extending the
time period for which gas service disconnection during inclement weather
conditions cannot be made. Due to the extension of the time period restricting
disconnections, delinquent KGS customers were allowed to continue gas service,
thus increasing uncollectible amounts. Higher gas costs in the 2000/2001
heating season also contributed to the increased uncollectible amounts. KGS
and other distribution companies in Kansas filed a joint application with the
KCC seeking approval to recover the additional uncollectible amounts incurred
during the 2000/2001 heating season until reviewed in the next rate case. The
KCC approved the deferral allowing the companies to seek recovery of the
extraordinary uncollectible account levels experienced in the 2000/2001
winter. KGS expects to file a rate case in late 2002. No accounting treatment
has yet been determined.
Southwest Litigation - In connection with the now terminated proposed
acquisition of Southwest Gas Corporation (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
original claim asked 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, punitive
damages and injunctive relief.
On June 29, 2001, the Company filed Motions for Summary Judgment. On September
26, 2001, the Court entered an order that, among other things, denied the
Motions for Summary Judgment by the Company on Southern Union's claim for
tortious interference with a prospective relationship with Southwest; however,
the Court's ruling limited any recovery by Southern Union to out-of-pocket
damages and punitive damages. The Company expects to file a Motion for Summary
Judgment seeking a dismissal of this single remaining claim and for punitive
damages. Based on discovery at this point, the Company believes that Southern
Union's out-of-pocket damages potentially recoverable at trial, exclusive of
legal fees and expenses, are less than $1.0 million.
Southwest filed a lawsuit against the Company and Southern Union alleging,
among other things, fraud and breach of contract. Southwest is seeking damages
in excess of $75,000. In an order dated January 4, 2002, the Court denied
Southwest's Motion for Partial Summary Judgment in its favor on its claims
against the Company, granted in part the Company's Motion for Summary Judgment
against Southwest, and denied the Company's Motion for Summary Judgment in
part with respect to Southwest's claims for fraud in the inducement and fraud.
Based on discovery at this point, the Company believes that Southwest's actual
damages potentially recoverable at trial, exclusive of legal fees and
expenses, are less than $5.5 million.
The lawsuits described above have been consolidated for purposes of trial. The
Court has entered an order setting the cases for jury trial on October 15,
2002.
Two substantially identical derivative actions were filed by shareholders
against 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 related to the planned
merger with Southwest for alleged 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
millions of dollars in 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 action for failure of the plaintiffs
to make a pre-suit demand on the Company's Board of Directors. In addition,
the Independent Directors and certain officers filed Motions to Dismiss the
actions for failure to state a claim. On February 26, 2001, the action was
stayed until one of the parties notifies the Court that a dissolution of the
stay is requested.
59
Except as set forth above or in the Legal Proceedings, the Company is unable
to estimate the possible loss, if any, associated with these matters. If
substantial damages were ultimately awarded, it could have a material adverse
effect on the Company's results of operations, cash flows 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 proposed acquisition of 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. ONEOK and its
subsidiaries are being represented by their insurance carrier in these cases.
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 period of time as
negotiated with the KDHE. Through December 31, 2001, the costs of the
investigations and risk analysis related to these manufactured gas sites have
been immaterial. Although remedial investigation and interim clean-up has
begun on four sites, limited information is available about the sites.
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.
In January 2001, the Yaggy storage facility, located in Hutchison, Kansas, was
idled following natural gas explosions and eruptions of natural gas geysers.
There are no known long-term environmental effects from the Yaggy storage
facility, however, the Company continues to perform tests in cooperation with
the KDHE.
Impact of Recently Issued Accounting Pronouncements - In July 2001, the FASB
issued Statement of Financial Accounting Standards No. 141, "Business
Combinations" (Statement 141), Statement of Financial Accounting Standards No.
142, "Goodwill and Other Intangible Assets" (Statement 142), and Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" (Statement 143). In October, 2001, the FASB issued Statement of
Financial Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (Statement 144).
Statement 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001. Statement 142 requires
that goodwill and intangible assets with indefinite useful lives no longer be
amortized, but instead tested for impairment at least annually in accordance
with the provisions of Statement 142. The Company adopted the provisions of
Statement 141 effective July 1, 2001, and Statement 142 effective January 1,
2002.
In connection with the Company's adoption of Statement 142, the Company is
required to perform an assessment of whether there is an indication that
goodwill, including equity-method goodwill, is impaired as of the date of
adoption. Any transitional impairment loss will be recognized as a cumulative
effect of a change in accounting principle in the Company's 2002 statement of
earnings.
60
As of December 31, 2001, the Company has unamortized goodwill in the amount of
$113.9 million. In addition, the Company has approximately $30.1 million of
goodwill related to its equity investments. The entire amount will be subject
to the transition provisions of Statement 142. Amortization expense related to
goodwill was $4.4 million and $3.2 million for the years ended December 31,
2001 and 2000, respectively. The Company discontinued the amortization of
goodwill effective January 1, 2002, with the adoption of Statement 142. In
accordance with provisions of Statement 142, the Company will complete its
analysis of goodwill for impairment no later than June 30, 2002.
Statement 143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Statement 143 is effective for fiscal years beginning after June 15, 2002.
Statement 144 retains the requirement to report separately discontinued
operations and extends that reporting to a component of an entity that either
has been disposed of or is classified as held for sale. Statement 144 is
effective for fiscal years beginning after December 15, 2001, and for interim
periods within those fiscal years. The Company is currently assessing the
impact of Statements 143 and 144 on its financial condition and results of
operations.
61
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, crude
oil and power prices. 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 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 market risk exposure.
The Company has from time to time 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,
2001, the Company is not a party to any weather derivative swaps.
KGS uses 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, 2001,
KGS had derivative instruments in place to hedge the cost of gas purchases for
6,500 MMMbtu.
For further discussion of trading activities and models and assumptions used
in the trading activities see the Critical Accounting Policies and Estimates
section of Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations. Also, see Note C of Notes to Consolidated Financial
Statements.
Interest Rate Risk - The Company is subject to the risk of fluctuation in
interest rates in the normal course of business due to the Company utilizing
variable rate debt. The Company manages interest rate risk through the use of
fixed rate debt, floating rate debt and interest rate swaps. In July 2001, the
Company entered into interest rate swaps on a total of $400 million in fixed
rate long-term debt. The interest rate under these swaps resets periodically
based on the three-month LIBOR or the six-month LIBOR at the reset date. In
October 2001, the Company entered into an agreement to lock in the interest
rates for each reset period under the swap agreements through the first
quarter of 2003. In December 2001, the Company entered into interest rate
swaps on a total of $200 million in fixed rate long-term debt. At December 31,
2001, a hypothetical 10 percent change in interest rates would result in an
annual $4.4 million change in interest costs related to short-term and
floating rate debt based on principal balances outstanding at these dates. At
December 31, 2000 the Company had no interest rate swaps.
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 (VAR). The quantification of market risk using VAR
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 VAR to determine
the potential reduction in the trading and price risk management portfolio
values arising from changes in market conditions over a defined period.
62
ONEOK's VAR 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.
VAR 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, 2001, the Company's estimated potential one-day favorable or
unfavorable impact on future earnings, as measured by the VAR, using a 95
percent confidence level and diversified correlation assuming one day to
liquidate positions was $5.1 million and the average of such value during the
year ended December 31, 2001 was estimated at $3.6 million.
Risk Policy and Oversight - ONEOK controls the scope of risk management,
marketing and trading operations through a comprehensive set of policies and
procedures involving senior levels of management. The Company's Board of
Directors affirms the risk limit parameters with its audit committee having
oversight responsibilities for the policies. A risk oversight committee,
comprised of corporate and business segment officers, oversees all activities
related to commodity price, credit and interest rate risk management,
marketing and trading activities. The committee also proposes risk metrics
including VAR and position loss limits. ONEOK has a corporate risk control
organization lead by the Vice-President of Risk Control, which is assigned
responsibility for establishing and enforcing the policies, procedures and
limits and evaluating the risks inherent in proposed transactions. Key risk
control activities include credit review and approval, credit and performance
risk measurement and monitoring, validation of transactions, portfolio
valuation, VAR and other risk metrics.
To the extent open commodity positions exist, fluctuating commodity prices can
impact the financial results and financial position of the Company either
favorably or unfavorably. As a result, the Company cannot predict with
precision the impact risk management decisions may have on the business,
operating results or financial position.
63
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, 2001, 2000, and 1999, and the related
consolidated statements of income, shareholders' equity, and cash flows for
the years ended December 31, 2001 and 2000, the year ended August 31, 1999 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, 2001, 2000, and 1999, and the results
of their operations and their cash flows for the years ended December 31, 2001
and 2000, the year ended August 31, 1999, and the four months ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Notes A and C to the consolidated financial statements, the
Company adopted the provisions of Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities,
effective January 1, 2001 and the provisions of Emerging Issues Task Force
98-10, Accounting for Contracts Involved in Energy Trading and Risk Management
Activities, effective January 1, 2000.
KPMG LLP
Tulsa, Oklahoma
February 14, 2002
64
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share amounts)
Operating Revenues (Note A) $ 6,803,146 $ 6,642,858 $ 806,478 $ 1,838,949
Cost of gas 5,894,361 5,845,726 587,681 1,213,478
----------------------------------------------------------------------------------------------------------------
Net Revenues 908,785 797,132 218,797 625,471
----------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 394,367 266,545 77,247 240,330
Depreciation, depletion, and amortization 157,310 143,351 43,227 129,704
General taxes 61,876 53,303 14,755 39,715
----------------------------------------------------------------------------------------------------------------
Total Operating Expenses 613,553 463,199 135,229 409,749
----------------------------------------------------------------------------------------------------------------
Operating Income 295,232 333,933 83,568 215,722
----------------------------------------------------------------------------------------------------------------
Other income, net 876 18,475 2,396 10,500
Interest expense 140,158 118,630 27,883 52,809
Income taxes 52,234 90,286 22,737 67,056
----------------------------------------------------------------------------------------------------------------
Income before cumulative effect of a change in
accounting principle 103,716 143,492 35,344 106,357
Cumulative effect of a change in
accounting principle, net of tax (Note A) (2,151) 2,115 - -
----------------------------------------------------------------------------------------------------------------
Net Income 101,565 145,607 35,344 106,357
Preferred stock dividends 37,100 37,100 12,367 37,247
----------------------------------------------------------------------------------------------------------------
Income Available for Common Stock $ 64,465 $ 108,507 $ 22,977 $ 69,110
================================================================================================================
Earnings Per Share of Common Stock (Note Q)
Basic $ 0.85 $ 1.23 $ 0.27 $ 0.86
================================================================================================================
Diluted $ 0.85 $ 1.23 $ 0.27 $ 0.86
================================================================================================================
Average Shares of Common Stock (Thousands)
Basic 99,449 98,340 100,742 103,102
Diluted 99,671 98,388 100,768 103,142
See accompanying Notes to Consolidated Financial Statements.
65
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31, December 31, December 31,
2001 2000 1999
-------------------------------------------------------------------------------------------------------------
Assets (Thousands of Dollars)
Current Assets
Cash and cash equivalents $ 28,229 $ 249 $ 72
Trade accounts and notes receivable, net 677,796 1,627,714 371,313
Materials and supplies 20,310 18,119 10,360
Gas in storage 82,694 57,800 124,511
Deferred income taxes - 10,425 8,383
Purchased gas cost adjustment 45,098 1,578 8,105
Assets from price risk management activities (Note C) 587,740 1,416,368 -
Customer deposits 41,781 120,800 40,928
Other current assets 78,321 71,906 31,714
-------------------------------------------------------------------------------------------------------------
Total Current Assets 1,561,969 3,324,959 595,386
-------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Marketing and Trading 3,979 2,795 2,047
Gathering and processing 1,040,195 1,001,994 385,260
Transportation and Storage 792,641 773,198 526,537
Distribution 1,985,177 1,860,181 1,766,057
Production 482,404 428,701 405,298
Power 118,193 75,891 17,193
Other 85,168 64,056 41,301
-------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 4,507,757 4,206,816 3,143,693
Accumulated depreciation, depletion, and amortization 1,234,789 1,110,803 1,021,915
-------------------------------------------------------------------------------------------------------------
Net Property 3,272,968 3,096,013 2,121,778
-------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Regulatory assets, net (Note E) 232,520 238,605 247,486
Goodwill 113,868 92,909 80,743
Assets from price risk management activities (Note C) 475,066 405,666 -
Investments and other 222,768 202,193 195,847
-------------------------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 1,044,222 939,373 524,076
-------------------------------------------------------------------------------------------------------------
Total Assets $ 5,879,159 $ 7,360,345 $ 3,241,240
=============================================================================================================
See accompanying Notes to Consolidated Financial Statements.
66
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31, December 31, December 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity (Thousdands of Dollars)
Current Liabilities
Current maturities of long-term debt $ 250,000 $ 10,767 $ 21,767
Notes payable 599,106 824,106 462,242
Accounts payable 390,479 1,247,519 237,653
Accrued taxes 11,528 8,735 359
Accrued interest 31,954 24,161 16,628
Customers' deposits 21,697 18,319 18,212
Liabilities from price risk management activities (Note C) 381,409 1,296,041 -
Other 132,244 96,913 29,852
------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,818,417 3,526,561 786,713
------------------------------------------------------------------------------------------------------------------------
Long-term Debt, excluding current maturities 1,498,012 1,336,082 775,074
Deferred Credits and Other Liabilities
Deferred income taxes 499,432 382,363 349,883
Liabilities from price risk management activities (Note C) 491,374 543,278 -
Lease obligation 122,011 137,131 -
Other deferred credits 184,623 209,973 178,046
------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,297,440 1,272,745 527,929
------------------------------------------------------------------------------------------------------------------------
Total Liabilities 4,613,869 6,135,388 2,089,716
------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note K)
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, 2001,
December 31, 2000, and December 31, 1999 199 199 199
Common stock, $0.01 par value:
authorized 300,000,000 shares;issued 63,438,441 shares
and outstanding 60,002,218 shares at December 31, 2001;
issued 63,198,610 shares and outstanding 59,176,550
shares at December 31, 2000; issued 63,198,610 shares and
outstanding 59,109,246 shares at December 31, 1999 634 316 316
Paid in capital (Note G) 902,269 895,668 894,976
Unearned compensation (2,000) (1,128) (1,846)
Accumulated other comprehensive income (Note D) (1,780) - -
Retained earnings 415,513 387,789 317,985
Treasury stock at cost: 3,436,223 shares at December 31, 2001;
4,022,060 shares at December 31, 2000 and 4,089,364 shares
at December 31, 1999 (49,545) (57,887) (60,106)
------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,265,290 1,224,957 1,151,524
------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 5,879,159 $ 7,360,345 $ 3,241,240
========================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
67
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------------------------
Operating Activities (Thousands of Dollars)
Net income $ 101,565 $ 145,607 $ 35,344 $ 106,357
Depreciation, depletion, and amortization 157,310 143,351 43,227 129,704
Unrecovered purchased gas cost adjustment 34,579 - - -
Gain on sale of assets (1,120) (27,050) - (6,639)
Gain on sale of equity investments (758) - - -
Income from equity investments (8,109) (4,025) (1,063) (1,560)
Deferred income taxes 134,933 26,143 28,317 14,925
Amortization of restricted stock 1,110 632 108 -
Allowance for doubtful accounts 43,495 6,048 436 4,029
Other 188 692 - 293
Changes in assets and liabilities:
Accounts and notes receivable 909,324 (1,262,449) (143,413) (54,716)
Inventories (11,906) (41,669) (15,920) 19,429
Unrecovered purchased gas costs (78,099) 6,527 (3,553) (16,720)
Regulatory assets (8,387) (6,303) (3,841) (6,261)
Other assets 37,201 (97,402) (5,457) (88,930)
Accounts payable and accrued liabilities (984,999) 1,168,871 84,627 41,320
Price risk management assets and liabilities (198,611) (64,574) - -
Deferred credits and other liabilities (6,211) 78,559 (1,812) (7,034)
-----------------------------------------------------------------------------------------------------------------
Cash Provided by Operating Activities 121,505 72,958 17,000 134,197
-----------------------------------------------------------------------------------------------------------------
Investing Activities
Changes in other investments, net 1,194 68 994 (59,422)
Acquisitions (16,015) (494,904) (17,482) (344,494)
Capital expenditures (341,567) (311,403) (76,016) (164,170)
Proceeds from sale of property 7,911 60,659 - 16,500
Proceeds from sale of equity investment 7,425 - - -
-----------------------------------------------------------------------------------------------------------------
Cash Used in Investing Activities (341,052) (745,580) (92,504) (551,586)
-----------------------------------------------------------------------------------------------------------------
Financing Activities
Borrowing of notes payable, net (225,000) 361,864 198,495 51,747
Change in bank overdraft 141,923 (168,145) (22,699) -
Issuance of debt 401,367 590,000 - 695,888
Payment of debt (7,583) (39,992) (36,952) (224,868)
Issuance of common stock 5,447 - - 1,087
Issuance (acquisition) of treasury stock, net 5,214 (453) (39,610) (22,570)
Dividends paid (73,841) (70,475) (28,060) (76,281)
Acquisition and cancellation of preferred stock - - - (3,298)
-----------------------------------------------------------------------------------------------------------------
Cash Provided by Financing Activities 247,527 672,799 71,174 421,705
-----------------------------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents 27,980 177 (4,330) 4,316
Cash and Cash Equivalents at Beginning of Period 249 72 4,402 86
-----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 28,229 $ 249 $ 72 $ 4,402
=================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
68
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
Other
Preferred Common Paid-in Unearned Comprehensive Retained Treasury
Stock Stock Capital Compensation Income Earnings Stock Total
(Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------------------------
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
Net income - - - - - 35,344 - 35,344
Re-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
===================================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
69
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Other
Preferred Common Paid-in Unearned Comprehensive Retained Treasury
Stock Stock Capital Compensation Income Earnings Stock Total
-----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
December 31, 1999 $ 199 $316 $894,976 $(1,846) $ - $ 317,985 $(60,106) $1,151,524
Net income - - - - - 145,607 - 145,607
Re-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
Net income - - - - - 101,565 - 101,565
Other comprehensive income - - - - (1,780) - - (1,780)
=========
Total comprehensive income 99,785
Effect of two-for-one stock split - 317 (317) - - - -
Re-issuance of treasury stock - - 866 - - - 7,278 8,144
Issuance of common stock
Stock purchase plans - 1 5,317 - - - - 5,318
Convertible preferred stock
dividends - $1.86 per share
for Series A - - - - - (37,100) - (37,100)
Acquisition of treasury stock - - - - - - (29) (29)
Issuance of restricted stock - - 715 (1,932) - - 1,217 -
Amortization of restricted stock - - - 1,110 - - - 1,110
Forfeitures of restricted stock - - 20 78 - - (124) (26)
Common stock dividends -
$0.62 per share - - - (128) - (36,741) - (36,869)
-----------------------------------------------------------------------------------------------------------------
December 31, 2001 $ 199 $634 $902,269 $(2,000) $ (1,780) $ 415,513 $(49,545) $1,265,290
=================================================================================================================
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A) SUMMARY OF 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 seven segments: Marketing and Trading, Gathering and
Processing, Transportation and Storage, Distribution, Production, Power and
Other.
The Marketing and Trading segment purchases and markets natural gas, primarily
in the mid-continent region of the United States. 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 Company (KGS). The
Production segment produces natural gas and oil and owns natural gas and oil
reserves. The Power segment produces and markets electricity to wholesale
customers. The Company's Other segment, whose results of operations are not
material, operates and leases the Company's headquarters building and parking
facility and has an investment in Magnum Hunter Resources, Inc., an independent
oil and gas company.
Critical Accounting Policies
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 and financial 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 statements 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.
71
Regulation - The Company's intrastate transmission pipelines and distribution
operations are subject to the rate regulation and accounting requirements of
the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC)
and Texas Railroad Commission (TRC). Certain other transportation activities of
the Company are subject to regulation by the Federal Energy Regulatory
Commission (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 (Statement 71). Allocation of
costs and revenues to accounting periods for rate-making and regulatory
purposes may differ from bases generally applied by non-regulated 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 they are recovered through rates. Total
regulatory assets resulting from this deferral process are approximately $232.5
million, $238.6 million and $247.5 million at December 31, 2001, 2000 and 1999,
respectively. Although no further unbundling of services is anticipated, should
this occur, certain of these assets may no longer meet the criteria for
following Statement 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 E of Notes to the
Consolidated Financial Statements.
KGS has a two-year rate moratorium, which expires in November 2002. ONG is not
subject to a rate moratorium.
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 assets on the lowest possible level.
Significant Accounting Policies
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, which is recorded in current price risk
management assets, 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 $1.3 million, $12.3 million, and $7.3 million at December 31, 2001,
2000 and 1999, respectively, compared to its value under the LIFO method of
$3.0 million, $4.6 million, and $5.7 million at December 31, 2001, 2000 and
1999, respectively. Current gas in storage for all other companies is
determined using the weighted average cost of gas method.
Derivative Instruments and Hedging Activities - To minimize the risk from
fluctuations in the price of natural gas and crude oil, the Company's
non-trading segments periodically enter into futures transactions, swaps, and
options in order to hedge anticipated sales of natural gas and crude oil
production, fuel requirements and inventories in its natural gas liquids
business. Interest rate swaps are also used to manage interest rate risk.
72
Prior to 2001, in order to qualify as a hedge, the price movements in the
underlying commodity derivatives had to be sufficiently correlated with the
hedged transaction. Gains and losses from hedging transactions were recognized
in income and 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 was not maintained, the Company ceased to account for the contract
as a hedge and recognized a gain or loss in current earnings to the extent the
contract results had not been offset by the effects of the price or interest
rate changes on the hedged item. If the underlying commodity or interest rate
transaction being hedged by the derivative was disposed of or otherwise
terminated, the gain or loss associated with such derivatives was no longer
deferred and was recognized in the period the underlying was eliminated.
On January 1, 2001, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (Statement 133), amended by Statement No. 137 and Statement No. 138.
Statement 137 delayed the implementation of Statement 133 until fiscal years
beginning after June 15, 2000. Statement 138 amended the accounting and
reporting standards of Statement 133 for certain derivative instruments and
hedging activities. Statement 138 also amends Statement 133 for decisions made
by the Financial Accounting Standards Board (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 Statement 133.
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 hedged 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 hedge, are reported in
earnings immediately.
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 (6.0 percent, 6.9 percent, 6.8 percent, and 7.8 percent, in
fiscal years 2001 and 2000, the four months ended December 31, 1999, and the
year ended August 31, 1999, 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 2.9 percent in fiscal year 2001, 3.0
percent in fiscal year 2000, 4.1 percent in the four months ended December 31,
1999, and 3.8 percent in the year ended August 31,1999. The average depreciation
rates for properties regulated by the KCC, excluding Mid-Continent Market Center
(the Market Center), were approximately 3.4 percent in fiscal year 2001, 3.3
percent in fiscal year 2000, 3.4 percent in the four months ended December 31,
1999, and 3.2 percent in the year ended August 31, 1999. The average
depreciation rates for the Market Center properties were 3.4 percent in fiscal
year 2001, 3.3 percent in fiscal year 2000, 3.1 percent in the four months ended
December 31, 1999, and 3.1 percent in the year ended August 31, 1999.
73
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 development 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.
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, Distribution and Power 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 when
oil and gas production volumes are delivered to the purchaser.
74
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 KCC 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.
Common Stock Options and Awards -The Company follows Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
(Statement 123) which permits, but does not require, a fair value based method
of accounting for stock-based employee compensation. Alternatively, Statement
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 Statement 123 in Note P of Notes to Consolidated Financial
Statements.
Earnings Per Common Share - In accordance with a pronouncement of the Financial
Accounting Standards Board's Staff at the Emerging Issues Task Force meeting in
April 2001, codified as EITF Topic No. D-95 (Topic D-95), the Company revised
its computation of earnings per common share (EPS). In accordance with Topic
D-95, the dilutive effect of the Company's Series A Convertible Preferred Stock
is now considered in the computation of basic EPS, utilizing the "if-converted"
method. Under the Company's "if-converted" method, the dilutive effect of the
Series A Convertible Preferred Stock on EPS cannot be less than the amount that
would result from the application of the "two-class" method of computing EPS.
The "two-class" method is an earnings allocation formula that determines EPS
for the common stock and the participating Series A Convertible Preferred Stock
according to dividends declared and participating rights in the undistributed
earnings. The Series A Convertible Preferred Stock is a participating
instrument with the Company's common stock with respect to the payment of
dividends. For all periods presented, the "two-class" method resulted in
additional dilution. Accordingly, EPS for such periods reflects this further
dilution. The Company restated the EPS amounts for all periods to be consistent
with the revised methodology. See Note Q of Notes to Consolidated Financial
Statements.
Use of Estimates - Certain amounts included in or affecting the Company's
financial statements and related disclosures must be estimated, requiring the
Company to make certain assumptions with respect to values or conditions which
cannot be known with certainty at the time the financial statements are
prepared. Items which may be estimated include, but are not limited to, the
economic useful life of assets, fair value of assets and liabilities,
obligations under employees benefit plans, provisions for uncollectible
accounts receivable, unbilled revenues for gas delivered but for which meters
have not been read, gas purchased expense for gas received but for which no
invoice has been received, the results of litigation and various other recorded
or disclosed amounts. Accordingly, the reported amounts of the Company's assets
and liabilities, revenues and expenses and related disclosures are necessarily
affected by these estimates.
The Company evaluates these estimates on an ongoing basis using historical
experience, consultation with experts and other methods the Company considers
reasonable in the particular circumstances. Nevertheless, actual results may
differ significantly from the estimates. Any effects on the Company's financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.
Reclassification - Certain amounts in prior period consolidated financial
statements have been reclassified to conform to the 2001 presentation.
75
(B) ACQUISITIONS AND DISPOSITIONS
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 $123.5 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 an operating
lease for a processing plant for which the Company established a liability of
approximately $157.7 million for an uneconomic lease obligation. The Company
also assumed some firm capacity lease obligations to unaffiliated parties for
which the Company established a reserve of approximately $220.1 million 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
---------------------------------------------------------------------------------
(Thousands of Dollars except per share amounts)
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 $ 1.29 $ 0.87
---------------------------------------------------------------------------------
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 $3.7
million of ongoing litigation costs to Other income, net for the year ended
December 31, 2001. The Company charged $13.7 million of previously deferred
transaction and litigation costs to Other income, net for the year ended
December 31, 2000. See Note K of Notes to Consolidated Financial Statements.
In May 1999, the Company acquired the Oklahoma midstream natural gas gathering
and processing assets of Koch Midstream Enterprises (Koch) for $285 million in
cash. The assets acquired include eight natural gas processing plants and
approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in
Oklahoma.
76
(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.
Risk Policy and Oversight - The Company controls the scope of risk management,
marketing and trading operations through a comprehensive set of policies and
procedures involving senior levels of management. The Company's Board of
Directors affirms the risk limit parameters with its audit committee having
oversight responsibilities for the policies. A risk oversight committee,
comprised of corporate and business segment officers, oversees all activities
related to commodity price, credit and interest rate risk management, marketing
and trading activities. The committee also proposes risk metrics including
value-at-risk (VAR) and position loss limits. The Company has a corporate risk
control organization lead by the Vice-President of Risk Control, which is
assigned responsibility for establishing and enforcing the policies, procedures
and limits and evaluating the risks inherent in proposed transactions. Key risk
control activities include credit review and approval, credit and performance
risk measurement and monitoring, validation of transactions, portfolio
valuation, VAR and other risk metrics.
To the extent open commodity positions exist, fluctuating commodity prices can
impact the financial results and financial position of the Company either
favorably or unfavorably. As a result, the Company cannot predict with
precision the impact risk management decisions may have on the business,
operating results or financial position.
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. The Marketing and Trading segment
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 2001 and 2000 are set forth as follows:
Fair Value Average Fair Value (a)
December 31, 2001 December 31, 2001
Assets Liabilities Assets Liabilities
---------------------------------------------------------------------------
(Thousands of Dollars)
Energy commodities $ 1,039,611 $ 854,219 $ 1,094,946 $ 975,359
---------------------------------------------------------------------------
(a) Computed using the ending balance at the end of each quarter.
77
Fair Value Average Fair Value (a)
December 31, 2000 December 31, 2000
Assets Liabilities Assets Liabilities
---------------------------------------------------------------------------
(Thousands of Dollars)
Energy 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, 2001.
Notional value - The notional contractual quantities associated with trading
price risk management activities are set forth as follows:
Volumes Volumes
Purchased Sold
---------------------------------------------------------
December 31, 2001:
Natural gas options (Bcf) 118.3 107.7
Crude oil options (MBbls) 5.6 5.4
Natural gas swaps (Bcf) 1,917.9 1,898.4
Crude oil swaps (MBbls) - 6.0
Natural gas futures (Bcf) 159.9 220.7
Crude oil futures (MBbls) 19.9 69.8
---------------------------------------------------------
December 31, 2000:
Natural gas options (Bcf) 75.3 65.7
Crude oil options (MBbls) - -
Natural gas swaps (Bcf) 683.6 733.8
Crude oil swaps (MBbls) - -
Natural gas futures (Bcf) 114.3 112.7
Crude oil futures (MBbls) - -
---------------------------------------------------------
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.
78
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 fair
value fluctuations. 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, at times,
interest rate swaps.
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.
In 2000, the Company entered into derivative instruments related to the
production of natural gas, most of which expired in 2001. These derivative
instruments were designed as cash flow hedges to hedge the Production segment's
exposure to changes in the price of natural gas. Changes in the fair value of
the derivative instruments are reflected initially in other comprehensive income
(loss) and subsequently realized in earnings when the forecasted transaction
affects earnings. The Company recorded a cumulative effect charge of $2.2
million, net of tax, in the income statement and $28 million, net of tax, in
accumulated other comprehensive loss to recognize at fair value the ineffective
and effective portions, respectively, of the losses on all derivative
instruments that are designated as cash flow hedging instruments, which
primarily consisted of costless option collars and swaps on natural gas
production.
The Company recognized $3.5 million in earnings, representing the ineffective
portion of the cash flow hedges for the year ended December 31, 2001. The
Company realized an $18.4 million loss in earnings that was reclassified from
accumulated other comprehensive loss resulting from the settlement of contracts
when the natural gas was sold. These gains and losses are reported in Operating
Revenues. Other comprehensive income of $1.8 million at December 31, 2001
includes approximately $1.3 million related to a cash flow hedge for 2002
production, which will be realized within the next year when the financial
transactions affect earnings.
In July 2001, the Company entered into interest rate swaps, which were
designated fair value hedges, on a total of $400 million in fixed rate long-term
debt. The interest rate under these swaps resets periodically based on the
three-month LIBOR or the six-month LIBOR at the reset date. In October 2001, the
Company entered into an agreement to lock in the interest rates for each reset
period under the swap agreements through the first quarter of 2003. In December
2001, the Company entered into interest rate swaps, which were designated fair
value hedges, on a total of $200 million in fixed rate long-term debt. The
Company recorded a $7.4 million net increase in price risk management assets and
liabilities to recognize the interest rate swaps at fair value. Long-term debt
was also increased to recognize the change in fair value of the related hedged
liability. See Note I of Notes to Consolidated Financial Statements
Fair value - The following table represents the estimated fair values of
derivative instruments related to the Company's non-trading price risk
management activities. The fair value is the carrying value for these
instruments at December 31,2001 and they have no carrying value at December 31,
2000 and August 31, 1999.
79
Approximate
Fair Value
----------------------------------------------------------------
(Thousands of Dollars)
December 31, 2001
Natural gas commodities - cash flow hedges $ 1,249
Interest rate swaps - fair value hedges $ 7,379
Natural gas commodities - other $ (3,997)
----------------------------------------------------------------
December 31, 2000
Natural gas commodities $ (41,623)
----------------------------------------------------------------
August 31, 1999
Natural gas commodities $ (11,540)
----------------------------------------------------------------
Notional value - The Company was a party to natural gas commodity derivative
instruments including swaps and options covering 19.0 Bcf and 32.9 Bcf of
natural gas for December 31, 2001 and 2000, respectively.
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, 2001 and 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 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, 2001
Cash and cash equivalents $ 28,229 $ 28,229
Accounts and notes receivable $ 677,796 $ 677,796
Notes payable $ 599,106 $ 599,106
Long-term debt $ 1,751,539 $ 1,773,798
-----------------------------------------------------------------
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
-----------------------------------------------------------------
80
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
----------------------------------------------------------------
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) COMPREHENSIVE INCOME
The table below gives an overview of Other comprehensive income at December 31,
2001, which includes the cumulative effect of a change in accounting principle
due to the adoption of Statement 133, realized and unrealized gains and losses
on derivative instruments and an adjustment to the Company's pension liability.
Year Ended
December 31, 2001
-----------------------------------------------------------------------------------
(Thousands of Dollars)
Net income $ 101,565
Other comprehensive income (loss):
Cumulative effect of a change in accounting principle $ (45,556)
Unrealized gains on derivative instruments 28,491
Realized losses in net income 18,383
Minimum pension liability adjustment (4,252)
-----------
Other comprehensive loss before taxes (2,934)
Income tax benefit on other comprehensive loss 1,154
--------------------------
Other comprehensive loss $ (1,780)
-----------
Comprehensive income $ 99,785
====================================================================================
81
(E) REGULATORY ASSETS
The table presents a summary of regulatory assets, net of amortization, at
December 31, 2001, 2000 and 1999.
December 31, December 31, December 31
2001 2000 1999
-----------------------------------------------------------------------------------------
(Thousands of Dollars)
Recoupable take-or-pay $ 75,336 $ 79,324 $ 84,343
Pension costs 11,124 15,306 19,487
Postretirement costs other than pension 60,170 61,069 62,207
Transition costs 21,598 22,199 22,746
Reacquired debt costs 22,351 23,209 24,068
Income taxes 28,365 30,727 23,337
Other 13,576 6,771 11,298
-----------------------------------------------------------------------------------------
Regulatory assets, net $ 232,520 $ 238,605 $ 247,486
=========================================================================================
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
December 31, 2001 Period
-------------------------------------------------------------------------------
(Thousands of Dollars) (Months)
Postretirement costs other than
pension -- Oklahoma $7,876 141
Income taxes - Oklahoma $9,374 114-130
Transition costs $21,598 431
-------------------------------------------------------------------------------
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 2001, the
Company has deferred approximately $801,000 associated with this Commission
directive. These deferred costs are included in the caption "Other" in the above
table of regulatory assets.
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 2001, the Company has deferred approximately $1.9
million associated with this program. These deferred costs are included in the
caption "Other" in the above table of regulatory assets.
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 J 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.
82
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.
Recovery through rates resulted in amortization of regulatory assets of
approximately $11.3 million and $10.6 million for the years ended December 31,
2001 and 2000, respectively, $3.1 million for the four months ended December 31,
1999, and $13.7 million for the year ended August 31, 1999.
(F) CAPITAL STOCK
The Company has approximately 176 million shares of authorized and unreserved
common stock available for issue. The Company issued Series A Convertible
Preferred Stock, par value $0.01 per share, at the time of the November 1997
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 3.0 times the dividend amount
declared in respect of each share of common stock for the first five years of
the agreement. In November 2002, the rate is reduced to 2.5 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 on an aggregate annual basis. The
dividend multiple has been adjusted to reflect the two-for-one common stock
split described below.
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 2.5 times the common stock dividend, and at no time will the dividend
be less than $1.50 per share on an aggregate annual basis during the first five
years after the agreement and not less than $1.80 on an aggregate annual basis
thereafter. 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 $0.50 or
subject to adjustment, 100 times the aggregate per share amount of all cash
dividends, and 100 times the aggregate per share amount (payable in kind) 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 two shares for each share of Series A Convertible Preferred Stock.
On January 18, 2001, the Company's Board of Directors approved, and on May 17,
2001, the shareholders of the Company voted in favor of, a two-for-one common
stock split, which was effected through the issuance 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 shares on June 11, 2001. The Company
retained the current par value of $0.01 per share for all shares of common
stock. Shareholders' equity reflects the stock split by reclassifying from Paid
in Capital to Common Stock an amount equal to the cumulative par value of the
additional shares issued to effect the split. All share and per share amounts
contained herein for all periods reflect this stock split. Outstanding
convertible preferred stock is assumed to convert to common stock on a
two-for-one basis in the calculations of earnings per share.
During 2001, the Company began a second stock buyback plan for up to 10 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, 2001, no shares have been
purchased under this plan. 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.
83
During 1999, the Company initiated a stock buyback plan for up to 15 percent of
its capital stock. The program authorized 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. This plan was terminated in April 2001. Through
April 30, 2001, the shares purchased under this plan totaled 5.1 million, which
has been adjusted for the two-for-one stock split. 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 were
financed with short-term debt or were made from available funds. This plan
expired in 2001.
The Board of Directors has reserved 12.0 million shares of ONEOK, Inc.'s common
stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which
424,000 shares were issued in fiscal year 2001, 190,000 shares were issued in
fiscal year 2000, 56,000 shares were issued in the four months ended December
31, 1999, and 254,000 shares were issued in the year ended August 31, 1999. In
January 2001, the Company amended and restated, in entirety, the existing Direct
Stock Purchase and Dividend Reinvestment Plan. The Company has reserved
approximately 13.2 million shares for the Thrift Plan for Employees of ONEOK,
Inc. and Subsidiaries less the number of shares issued to date under this plan.
Under the most restrictive covenants of the Company's loan agreements, $226.6
million (54.5 percent) of retained earnings were available to pay dividends at
December 31, 2001.
(G) PAID IN CAPITAL
Paid in capital was $338.1 million, $331.5 million and $330.8 million for common
stock at December 31, 2001, 2000 and 1999, respectively. Paid in capital for
convertible preferred stock was $564.2 million at December 31, 2001, 2000 and
1999.
(H) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE
Commercial paper and short-term notes payable totaling $599.1 million, of which
$275.0 million was used to purchase natural gas that was injected into storage,
was outstanding at December 31, 2001. Commercial paper and short-term notes
payable totaling $824.1 million and $462.2 million were outstanding at December
31, 2000 and 1999, respectively. The commercial paper and notes carried average
interest rates of 4.25 percent, 6.53 percent, and 6.47 percent at December 31,
2001, 2000 and 1999, respectively. The Company has a $850 million short-term
unsecured revolving credit facility, which provides 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 amounts were outstanding under the line of credit and no
compensating balance requirements existed at December 31, 2001. Maximum
short-term debt from all sources as approved by the Company's Board of Directors
is $1.2 billion.
(I) LONG-TERM DEBT
The aggregate maturities of long-term debt outstanding at December 31, 2001, are
$250 million; $10 million; $50 million; $360 million; and $310 million for 2002
through 2006, 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, 2001, are unsecured.
In 2001, the Company issued a $400 million note at a rate of 7.125%. The
proceeds from the note were used to refinance short-term debt. 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.
84
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, at times, interest rate swaps.
In July 2001, the Company entered into interest rate swaps on a total of $400
million in fixed rate long-term debt. The interest rate under these swaps resets
periodically based on the three-month LIBOR or the six-month LIBOR at the reset
date. In October 2001, the Company entered into an agreement to lock in the
interest rates for each reset period under the swap agreements through the first
quarter of 2003. In December 2001, the Company entered into interest rate swaps
on a total of $200 million in fixed rate long-term debt. The Company recorded a
$7.4 million net increase in price risk management assets to recognize at fair
value its derivatives that are designated as fair value hedging instruments.
Long-term debt was increased by approximately $7.4 million to recognize the
change in fair value of the related hedged liability. The swaps generated $5.3
million of interest rate savings during 2001. See further discussion of interest
rate risk in Note C of Notes to the Consolidated Financial Statements.
December 31, December 31, December 31,
2001 2000 1999
-------------------------------------------------------------------------------
(Thousands of Dollars)
Long-term Notes Payable
6.43% due 2000 $ - $ - $ 5,000
7.25% due 2001 - 767 1,535
3.95% due 2002 240,000 240,000 -
8.44% due 2004 40,000 40,000 40,000
7.75% due 2005 350,000 350,000 -
7.75% due 2006 300,000 300,000 300,000
8.32% due 2007 24,000 28,000 32,000
6.00% due 2009 100,000 100,000 100,000
7.125% due 2011 400,000 - -
6.40% due 2019 94,913 96,502 99,308
9.70% due 2019 - - 8,826
9.75% due 2020 - - 15,305
6.50% due 2028 93,880 95,420 98,757
6.875% due 2028 100,000 100,000 100,000
-------------------------------------------------------------------------------
Total Long-term Notes Payable 1,742,793 1,350,689 800,731
Change in fair value of hedged debt 7,379 - -
Other long-term debt 1,367 - -
Unamortized debt discount 3,527 3,840 3,890
Current maturities 250,000 10,767 21,767
-------------------------------------------------------------------------------
Long-term debt $ 1,498,012 $ 1,336,082 $ 775,074
===============================================================================
(J) EMPLOYEE BENEFIT PLANS
Retirement Plans - The Company has defined benefit and defined contribution
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 insurance benefits to
substantially all employees who retire under the Retirement Plans with at least
five years of service. Non-bargaining unit employees retiring between the ages
of 50 and 55 have access to the Company provided medical benefits.
Non-bargaining unit employees retiring at age 55 or older are eligible for both
the Company provided medical and life insurance benefits. The plans are
contributory, with retiree contributions adjusted periodically, and contain
other cost-sharing features such as deductibles and coinsurance.
85
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, 2001, 2000 and 1999.
Pension Benefits Postretirement Benefits
December 31, December 31,
----------------------------------------- ----------------------------------------
2001 2000 1999 2001 2000 1999
--------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Change in Benefit Obligation
Benefit obligation, beginning of period $ 481,879 $ 495,061 $ 504,865 $ 136,157 $ 146,589 $ 160,371
Service cost 9,751 9,365 2,829 3,074 3,566 1,297
Interest cost 36,188 34,806 11,431 10,195 10,312 3,636
Participant contributions - - - 1,476 1,173 334
Plan amendments - - - - (7,816) (10,893)
Actuarial (gain)/loss 21,504 (25,965) (13,973) 13,626 (5,228) (4,786)
Benefits paid (33,226) (31,388) (10,091) (9,969) (12,439) (3,370)
--------------------------------------------------------------------------------------------------------------------------------
Benefit obligation, end of period $ 516,096 $ 481,879 $ 495,061 $ 154,559 $ 136,157 $ 146,589
================================================================================================================================
Change in Plan Assets
Fair value of assets, beginning of period $ 747,635 $ 640,330 $ 660,386 $ 24,110 $ 17,837 $ 17,500
Actual return on assets (128,527) 137,791 (10,198) 374 1,941 (674)
Employer contributions 1,407 902 233 3,263 4,332 1,011
Benefits paid (33,226) (31,388) (10,091) - - -
--------------------------------------------------------------------------------------------------------------------------------
Fair value of assets, end of period $ 587,289 $ 747,635 $ 640,330 $ 27,747 $ 24,110 $ 17,837
================================================================================================================================
Funded status - over(under) $ 71,193 $ 265,756 $ 145,269 $ (126,812) $ (112,048) $ (128,752)
Unrecognized net asset (1,248) (1,715) (2,182) - - -
Unrecognized transition obligation - - - 22,903 24,758 34,332
Unrecognized prior service cost 6,112 6,934 7,756 - - 877
Unrecognized net (gain)loss 27,177 (188,392) (79,969) 25,976 9,689 16,356
Activity subsequent to measurement date - - - 586 (793) (998)
--------------------------------------------------------------------------------------------------------------------------------
(Accrued)prepaid pension cost $ 103,234 $ 82,583 $ 70,874 $ (77,347) $ (78,394) $ (78,185)
================================================================================================================================
Actuarial Assumptions
Discount rate 7.35% 7.75% 7.25% 7.35% 7.75% 7.25%
Expected rate of return 9.85% 9.25% 9.25% 9.85% 9.25% 9.25%
Compensation increase rate 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
86
Pension Benefits
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
---------------------------------------------------------------------------------------------------------------
Components of Net Periodic Benefit Cost
Service cost $ 9,751 $ 9,365 $ 2,829 $ 9,282
Interest cost 36,188 34,806 11,431 32,832
Expected return on assets (61,161) (55,566) (17,581) (46,846)
Amortization of unrecognized net asset at adoption (467) (467) (156) (467)
Amortization of unrecognized prior service cost 822 822 274 177
Amortization of (gain)/loss (4,377) 233 92 786
---------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ (19,244) $ (10,807) $ (3,111) $ (4,236)
===============================================================================================================
Postretirement Benefits
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------------------------
Components of Net Periodic Benefit Cost
Service cost $ 3,074 $ 3,566 $ 1,297 $ 4,036
Interest cost 10,195 10,312 3,636 10,055
Expected return on assets (2,364) (1,792) (616) (1,325)
Amortization of unrecognized net transition obligation
at adoption 1,954 2,512 1,025 3,235
Amortization of unrecognized prior service cost - - 66 -
Amortization of loss 234 430 154 688
-----------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 13,093 $ 15,028 $ 5,562 $ 16,689
=================================================================================================================
For measurement purposes, a 6.10 percent annual rate of increase in the per
capita cost of covered medical benefits (i.e., medical cost trend rate) was
assumed for 2001. 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, 2001, by $12.3 million and the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for the year ended
December 31, 2001, by $1.3 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, 2001, by $10.3 million and the aggregate
of the service and interest cost components of net periodic postretirement
benefit cost for the year ended December 31, 2001, by $1 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 $8.8
million and $6.7 million in fiscal years 2001 and 2000, respectively; $2.3
million for the four months ended December 31, 1999; and $6.3 million for the
year ended August 31, 1999.
Postemployment Benefits - The Company pays postemployment benefits to former or
inactive employees after employment but before normal retirement in compliance
with specific separation agreements.
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.
87
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 for the regulatory asset established for
postretirement and postemployment benefit costs totaling approximately $52.3
million at December 31, 2001.
(K) 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 in fiscal
years 2001 and 2000, $2.9 million for the four months ended December 31, 1999,
and $5.8 million for the year ended August 31,1999. Estimated future minimum
rental payments for the lease are $9.3 million for each of the years ending
December 31, 2002 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 years 2001 and 2000,
$1.0 million for the four months ended December 31, 1999, and $2.8 million for
the year ended August 31,1999, for various subleases. Estimated minimum future
rental payments to be received under existing contracts for subleases are $3.2
million in 2002, $2.7 million in 2003, $2.1 million in 2004, $1.3 million in
2005, $1.2 million in 2006 and a total of $0.7 million thereafter.
Other operating leases include a gas processing plant, office buildings, and
equipment. Future minimum lease payments under non-cancelable operating leases
(with initial or remaining lease terms in excess of one year) as of December 31,
2001 are $33.0 million in 2002, $25.1 million in 2003, $24.6 million in 2004,
$27.4 million in 2005 and $40.7 million in 2006. The above amounts include the
following minimum lease payments relating to the lease of a gas processing
plant: $21.3 million in 2002, $16.2 million in 2003, $20.9 million in 2004,
$24.2 million in 2005 and $37.7 million in 2006. 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.
Enron - Certain of the financial instruments discussed previously in Note C of
the Notes to the Consolidated Financial Statements have Enron North America as
the counterparty. Enron Corporation and various subsidiaries, including Enron
North America (Enron), filed for protection from creditors under Chapter 11 of
the United States Bankruptcy Code on December 3, 2001. The Company has provided
an allowance for forward financial positions and also established an allowance
for uncollectible accounts relating to previously settled financial and physical
positions with Enron at December 31, 2001. The Company estimates its claim
against Enron to be approximately $74 million. The ultimate resolution of any
claims ONEOK may have against Enron cannot be determined at this time.
88
The filing of the voluntary bankruptcy proceeding by Enron created a possible
technical default related to various financing leases tied to the Company's
Bushton gas processing plant in south central Kansas. The Company acquired the
Bushton gas processing plant and related leases from KMI in April 2000. KMI had
previously acquired the plant and leases from Enron. Enron is one of three
guarantors of these Bushton plant leases; however, the Company is the primary
guarantor. In January 2002, the company was granted a waiver on the possible
technical default related to these leases. The Company will continue to make
all payments due under these leases.
Southwest Gas Corporation - In connection with the now terminated proposed
acquisition of Southwest Gas Corporation (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 original claim asked 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.
On June 29, 2001, the Company filed Motions for Summary Judgment. On September
26, 2001, the Court entered an order that, among other things, denied the
Motions for Summary Judgment by the Company on Southern Union's claim for
tortious interference with a prospective relationship with Southwest; however,
the Court's ruling limited any recovery by Southern Union to out-of-pocket
damages and punitive damages. The Company expects to file a Motion for Summary
Judgment seeking a dismissal of this single remaining claim and for punitive
damages. Based on discovery at this point, the Company believes that Southern
Union's out-of-pocket damages potentially recoverable at trial, exclusive of
legal fees and expenses, are less than $1.0 million.
Southwest filed a lawsuit against the Company and Southern Union alleging,
among other things, fraud and breach of contract. Southwest is seeking damages
in excess of $75,000. In an order dated January 4, 2002, the Court denied
Southwest's Motion for Partial Summary Judgment in its favor on its claims
against the Company, granted in part the Company's Motion for Summary Judgment
against Southwest, and denied the Company's Motion for Summary Judgment in part
with respect to Southwest's claims for fraud in the inducement and fraud. Based
on discovery at this point, the Company believes that Southwest's actual
damages potentially recoverable at trial, exclusive of legal fees and expenses,
are less than $5.5 million.
The lawsuits described above have been consolidated for purposes of trial. The
Court has entered an order setting the cases for jury trial on October 15, 2002.
Two substantially identical derivative actions were filed by shareholders
against 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 related to the planned merger
with Southwest for alleged 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
millions of dollars in 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 action for failure of the plaintiffs to
make a pre-suit demand on the Company's Board of Directors. In addition, the
Independent Directors and certain officers filed Motions to Dismiss the actions
for failure to state a claim. On February 26, 2001, the action was stayed until
one of the parties notifies the Court that a dissolution of the stay is
requested.
Except as set forth above, the Company is unable to estimate the possible loss,
if any, associated with these matters. If substantial damage were ultimately
awarded, it could have a material adverse effect on the Company's results of
operations, cash flows 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 proposed acquisition of Southwest.
89
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 period of time as negotiated with
the KDHE. Through December 31, 2001, the costs of the investigations and risk
analysis related to these manufactured gas sites have been immaterial. Although
remedial investigation and interim clean-up has begun on four sites, limited
information is available about the sites. 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 unaffiliated 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.
In January 2001, the Yaggy storage facility, located in Hutchison, Kansas, was
idled following natural gas explosions and eruptions of natural gas geysers.
There are no known long-term environmental effects from the Yaggy storage
facility, however, the Company continues to perform tests in cooperation with
the KDHE.
Other - The OCC staff filed an application on February 1, 2001 to review the
gas procurement practices of ONG in acquiring its gas supply for the 2000/2001
heating season to determine if they were consistent with least cost procurement
practices and whether the Company's decisions resulted in fair, just and
reasonable costs being borne by its customers. In a hearing on October 31,
2001, the OCC issued an oral ruling that ONG not be allowed to recover the
balance in the Company's unrecovered purchased gas cost (UPGC) account related
to the unrecovered gas costs from the 2000/2001 winter effective with the first
billing cycle for the month following the issuance of a final order. A final
order, which was issued on November 20, 2001, halted the recovery process
effective December 1, 2001. On December 12, 2001, the OCC approved a request to
stay the order and will allow ONG to commence collecting gas charges, subject
to refund should the Company ultimately lose the case. The stay will be in
effect while the matter is before the Oklahoma Supreme Court. Although the
Company believes that decisions made by the Company were prudent based upon the
facts and circumstances existing at the time the decisions were made, which is
the standard applicable to the Proceeding as stated by the OCC, the Company has
taken a charge of $34.6 million in the fourth quarter of 2001 as a result of
this order. This charge is recorded as an increase in gas purchase expense in
the Distribution segment. The Company will continue to assert its legal rights
and is hopeful that a resolution of this issue can be negotiated.
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. ONEOK and its subsidiaries are being represented by their insurance
carrier in these cases. The Company is vigorously defending itself against all
claims.
In April 1998, an application filed with the OCC alleged that ONG has charged
and continues to charge its ratepayers, through its PGA, excessive, imprudent
and unwarranted gas purchase costs related to a contract with Dynamic Energy
Resources, Inc. The Consumer Services Divisions (CSD) of the OCC conducted a
review of the contract. The applicants and the CSD filed their direct testimony
in February 2002. ONG is to file rebuttal testimony on April 21, 2002. The
hearing before the Commission is scheduled for June 3, 2002.
90
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.
(L) INCOME TAXES
The provisions for income taxes are as follows:
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Current income taxes
Federal $ (69,273) $ 55,764 $ (6,345) $ 48,760
State (13,426) 8,379 765 3,371
-------------------------------------------------------------------------------------------------------------
Total current income taxes (82,699) 64,143 (5,580) 52,131
-------------------------------------------------------------------------------------------------------------
Deferred income taxes
Federal 127,750 23,947 25,938 13,671
State 7,183 2,196 2,379 1,254
-------------------------------------------------------------------------------------------------------------
Total deferred income taxes 134,933 26,143 28,317 14,925
-------------------------------------------------------------------------------------------------------------
Total provision for income taxes before
cummulative effect of a change in accounting principle 52,234 90,286 22,737 67,056
-------------------------------------------------------------------------------------------------------------
Total provision for income taxes for the
cummulative effect of a change in accounting principle (1,356) 1,334 - -
-------------------------------------------------------------------------------------------------------------
Total provision for income taxes $ 50,878 $ 91,620 22,737 $67,056
=============================================================================================================
Following is a reconciliation of the provision for income taxes.
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Pretax income $152,442 $233,778 $58,081 $173,413
Federal statutory income tax rate 35% 35% 35% 35%
-----------------------------------------------------------------------------------------------------------------
Provision for federal income taxes 53,355 81,822 20,328 60,695
Amortization of distribution property investment tax credit (764) (807) (302) (1,103)
State income taxes, net of federal tax benefit (4,058) 6,874 2,044 5,737
Other, net 2,345 3,731 667 1,727
-----------------------------------------------------------------------------------------------------------------
Actual income tax expense $ 50,878 $91,620 $22,737 $ 67,056
=================================================================================================================
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.
91
December 31, December 31, December 31,
2001 2000 1999
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Deferred tax assets
Accrued liabilities not deductible until paid $ 180,331 $ 173,493 $ 8,383
Net operating loss carryforward 36,972 1,665 1,317
Regulatory assets 9,956 4,734 3,760
Other 2,057 4,277 1,982
---------------------------------------------------------------------------------------------------
Total deferred tax assets 229,316 184,169 15,442
Valuation allowance for net operating loss
carryforward expected to expire prior to utilization 6,693 1,230 882
---------------------------------------------------------------------------------------------------
Net deferred tax assets 222,623 182,939 14,560
Deferred tax liabilities
Excess of tax over book depreciation and depletion 578,876 461,560 262,515
Investment in joint ventures 12,198 11,280 11,414
Regulatory assets 95,836 78,186 75,407
Other 38,472 3,851 6,724
---------------------------------------------------------------------------------------------------
Total deferred tax liabilities 725,382 554,877 356,060
---------------------------------------------------------------------------------------------------
Net deferred tax liabilities $ 502,759 $ 371,938 $341,500
===================================================================================================
The Company has remaining net operating loss carryforwards for federal and
state income tax purposes of approximately $84 million and $115 million,
respectively, at December 31, 2001, which expire, unless previously utilized,
at various dates through the year 2020. At December 31, 2001, the Company had
$6.7 million in deferred investment tax credits recorded in other deferred
credits, which will be amortized over the next 14 years.
(M) 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 seven segments: (1) the Marketing
and Trading segment markets natural gas to wholesale and retail 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; (6) the Power segment markets electricity
to wholesale customers, and (7) the Other segment primarily operates and leases
the Company's headquarters building and a related parking facility and owns an
investment in Magnum Hunter Resources, Inc.
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 Power segment has a signed definitive agreement with an unaffiliated
company for a 15-year term providing the customer with the right to purchase
approximately 25 percent of the plant's generating capacity. There are no
single external customers from which the Company receives ten percent or more
of consolidated revenues.
92
Gathering Transportation
YearEnded Marketing and and and Other and
December 31, 2001 Trading Processing Storage Distribution Production Power Eliminations
-----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $ 4,293,526 $ 814,963 $ 76,837 $1,506,420 $ 94,144 $ 28,092 $ (10,836)
Intersegment sales 614,698 499,854 102,133 4,548 26,173 - (1,247,406)
-----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 4,908,224 $ 1,314,817 $ 178,970 $1,510,968 $120,317 $ 28,092 $ (1,258,242)
-----------------------------------------------------------------------------------------------------------------------------------
Netrevenues $ 103,429 $ 189,621 $ 129,344 $ 353,393 $120,317 $ 6,858 $ 5,823
Operating costs $ 31,488 $ 116,853 $ 52,497 $ 230,137 $ 27,361 $ 1,358 $ (3,451)
Depreciation, depletion and
amortization $ 597 $ 29,201 $ 19,190 $ 69,159 $ 35,017 $ 2,014 $ 2,132
Operatingincome $ 71,344 $ 43,567 $ 57,657 $ 54,097 $ 57,939 $ 3,486 $ 7,142
Cumulative effect of a change
in accounting principle,
net of tax $ - $ - $ - $ - $ (2,151) $ - $ -
Incomefromequity
investments $ - $ - $ 2,946 $ - $ 111 $ - $ 5,052
Total assets $ 1,369,220 $ 1,322,438 $ 797,331 $1,688,670 $321,720 $122,404 $ 257,376
Capital expenditures $ 1,184 $ 51,442 $ 35,911 $ 129,937 $ 55,974 $ 42,302 $ 24,817
-----------------------------------------------------------------------------------------------------------------------------------
Gathering Transportation
Year Ended Marketing and and and Other and
December 31, 2000 Trading Processing Storage Distribution Production Power Eliminations
-----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $4,362,024 $ 839,388 $ 111,644 $1,270,369 $ 50,686 $ - $ 8,747
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)
-----------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 66,482 $ 224,012 $ 125,582 $ 377,277 $ 70,355 $ - $ (66,576)
Operating costs $ 14,321 $ 90,501 $ 44,785 $ 211,629 $ 24,228 $ - $ (65,616)
Depreciation, depletion and
amortization $ 887 $ 22,692 $ 18,639 $ 67,717 $ 30,884 $ - $ 2,532
Operating income $ 51,274 $ 110,819 $ 62,158 $ 97,931 $ 15,243 $ - $ (3,492)
Cumulative effect of a change
in accounting principle,
net of tax $ 2,115 $ - $ - $ - $ - $ - $ -
Income from equity
investments $ - $ - $ 3,240 $ - $ 125 $ - $ 660
Total assets $3,035,227 $ 1,507,546 $ 661,894 $2,007,351 $308,041 $ 77,426 $ (237,140)
Capital expenditures $ 815 $ 32,383 $ 37,701 $ 124,983 $ 34,035 $ 58,697 $ 22,789
-----------------------------------------------------------------------------------------------------------------------------------
YearEnded
December 31, 2001 Total
-----------------------------------------------
Sales to unaffiliated
customers $6,803,146
Intersegment sales $ -
-----------------------------------------------
Total Revenues $6,803,146
-----------------------------------------------
Netrevenues $ 908,785
Operating costs $ 456,243
Depreciation, depletion and
amortization $ 157,310
Operatingincome $ 295,232
Cumulative effect of a change
in accounting principle,
net of tax $ (2,151)
Incomefromequity
investments $ 8,109
Total assets $5,879,159
Capital expenditures $ 341,567
-----------------------------------------------
Year Ended
December 31, 2000 Total
-----------------------------------------------
Sales to unaffiliated
customers $6,642,858
Intersegment sales $ -
-----------------------------------------------
Total Revenues $6,642,858
-----------------------------------------------
Net revenues $ 797,132
Operating costs $ 319,848
Depreciation, depletion and
amortization $ 143,351
Operating income $ 333,933
Cumulative effect of a change
in accounting principle,
net of tax $ 2,115
Income from equity
investments $ 4,025
Total assets $7,360,345
Capital expenditures $ 311,403
-----------------------------------------------
93
Marketing Gathering Transportation
Four Months Ended and and and Other and
December 31, 1999 Trading Processing Storage Distribution Production Power Eliminations
-------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $365,224 $ 63,869 $ 13,283 $ 337,890 $ 18,692 $ - $ 7,520
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)
-------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 11,493 $ 19,413 $ 34,491 $ 129,870 $ 23,471 $ - $ 59
Operating costs $ 3,344 $ 8,588 $ 10,184 $ 69,455 $ 7,245 $ - $ (6,814)
Depreciation, depletion and
amortization $ 242 $ 2,513 $ 5,124 $ 24,815 $ 9,715 $ - $ 818
Operating income $ 7,907 $ 8,312 $ 19,183 $ 35,600 $ 6,511 $ - $ 6,055
Income (loss) from equity
investments $ - $ - $ 1,074 $ - $ (11) $ - $ -
Total assets $287,375 $368,904 $437,561 $1,776,273 $301,821 $19,330 $ 49,976
Capital expenditures $ 9 $ 14,613 $ 5,837 $ 34,167 $ 6,411 $13,445 $ 1,534
-------------------------------------------------------------------------------------------------------------------------------
Four Months Ended
December 31, 1999 Total
-------------------------------------------
Sales to unaffiliated
customers $ 806,478
Intersegment sales $ -
-------------------------------------------
Total Revenues $ 806,478
-------------------------------------------
Net revenues $ 218,797
Operating costs $ 92,002
Depreciation, depletion and
amortization $ 43,227
Operating income $ 83,568
Income (loss) from equity
investments $ 1,063
Total assets $3,241,240
Capital expenditures $ 76,016
-------------------------------------------
Marketing Gathering Transportation
Year Ended and and and Other and
August 31, 1999 Trading Processing Storage Distribution Production Power Eliminations
--------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $772,331 $ 72,277 $ 27,892 $ 915,782 $ 44,026 $ - $ 6,641
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)
--------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 35,443 $ 31,311 $102,910 $ 393,461 $ 66,894 $ - $ (4,548)
Operating costs $ 9,069 $ 11,207 $ 28,919 $ 219,945 $ 19,128 $ - $ (8,223)
Depreciation, depletion and
amortization $ 503 $ 3,562 $ 13,852 $ 75,443 $ 34,073 $ - $ 2,271
Operating income $ 25,871 $ 16,542 $ 60,139 $ 98,073 $ 13,693 $ - $ 1,404
Income from equity
investments $ - $ - $ 1,501 $ - $ 59 $ - $ -
Total assets $269,444 $343,133 $373,742 $1,722,381 $310,715 $ 4,047 $ 1,483
Capital expenditures $ 448 $ 8,557 $ 32,618 $ 98,685 $ 16,046 $ 3,748 $ 4,068
--------------------------------------------------------------------------------------------------------------------------------
Year Ended
August 31, 1999 Total
-------------------------------------------
Sales to unaffiliated
customers $ 1,838,949
Intersegment sales $ -
-------------------------------------------
Total Revenues $ 1,838,949
-------------------------------------------
Net revenues $ 625,471
Operating costs $ 280,045
Depreciation, depletion and
amortization $ 129,704
Operating income $ 215,722
Income from equity
investments $ 1,560
Total assets $ 3,024,945
Capital expenditures $ 164,170
-------------------------------------------
(N) 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, 2001 and 2000, respectively,
follows:
94
Year Ended First Second Third Fourth
December 31, 2001 Quarter Quarter Quarter Quarter
---------------------------------------------------------------------------------------------------
(Thousands of dollars, except per share amounts)
Operating revenues $2,956,924 $1,402,399 $1,126,696 $1,317,127
Operating income $ 143,046 $ 71,942 $ 55,733 $ 24,511
Other income (expense) $ 3,299 $ 566 $ (1,914) $ (1,075)
Income taxes $ 41,800 $ 12,651 $ 301 $ (2,518)
Net Income (Loss) $ 64,859 $ 23,608 $ 18,787 $ (5,689)
Earnings per share of common stock
Basic $ 0.55 $ 0.20 $ 0.16 $ (0.05)
Diluted $ 0.54 $ 0.20 $ 0.16 $ (0.05)
Dividends per share of common stock $ 0.155 $ 0.155 $ 0.155 $ 0.155
Average shares of common stock outstanding
Basic 99,214 99,407 99,521 99,648
Diluted 99,596 99,733 99,633 99,887
---------------------------------------------------------------------------------------------------
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 $ 0.53 $ 0.23 $ 0.01 $ 0.38
Diluted $ 0.53 $ 0.23 $ 0.01 $ 0.38
Dividends per share of common stock $ 0.155 $ 0.155 $ 0.155 $ 0.155
Average shares of common stock outstanding
Basic 98,376 98,284 98,292 98,408
Diluted 98,378 98,292 98,300 98,752
---------------------------------------------------------------------------------------------------
During the fourth quarter of 2001, the Company took a charge of $34.6 million
against operating income related to unrecovered gas costs associated with the
2000/2001 winter. The Company also took a charge of $37.4 million against
operating income during the same period related to the Enron bankruptcy filing.
For further discussion of these charges, see Note K of the Notes to
Consolidated Financial Statements.
95
(O) SUPPLEMENTAL CASH FLOW INFORMATION
The table presents supplemental information relative to the Company's cash
flows for the years ended December 31, 2001 and 2000, the four months ended
December 31, 1999, and the year ended August 31, 1999.
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
--------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Cash paid during the year
Interest (including amounts capitalized) $ 132,364 $ 111,097 $ 16,605 $ 50,498
Income taxes $ 13,050 $ 57,579 $ - $ 59,466
--------------------------------------------------------------------------------------------------------------------
Noncash transactions
Treasury stock transferred to compensation plans $ - $ 61 $ 2,071 $ -
Gas received as payment in kind $ - $ - $ - $ 135
--------------------------------------------------------------------------------------------------------------------
Acquisitions
Property, plant, and equipment $ 1,515 $ 832,849 $ 17,482 $ 338,138
Current assets - 74,012 - -
Current liabilities - (20,996) - -
Regulatory assets and goodwill 14,500 17,663 - 10,817
Lease obligation - (157,651) - -
Price risk management activities - (239,660) - -
Deferred credits - (11,313) - -
Deferred income taxes - - - (4,461)
--------------------------------------------------------------------------------------------------------------------
Cash paid - acquisitions $ 16,015 $ 494,904 $ 17,482 $ 344,494
====================================================================================================================
(P) STOCK BASED COMPENSATION
Stock Splits - Due to the 2001 stock split, the number of shares and related
exercise prices have been adjusted to maintain both the total market value of
common stock underlying the options and Employee Stock Purchase Plan (ESPP)
share elections, and the relationship between the fair market value of the
common stock and the exercise price of the options and ESPP share elections.
STOCK OPTION PLANS
Long-Term Incentive Plan - The ONEOK, Inc. Long-Term Incentive Plan provides
for the granting of incentive stock options, non-statutory stock options, stock
bonus awards, and restricted stock awards to key employees and the granting of
stock awards to non-employee directors. The Company has reserved approximately
7.8 million shares of common stock for the plan less the number of shares
previously issued under the plan. The maximum numbers of shares for which
options or other awards may be granted to any employee during any year is
300,000.
Under the plan, options may be granted by the Executive Compensation Committee
(the Committee). Stock options and awards may be granted at any time until all
shares authorized are transferred, except that no incentive stock option may be
granted under the plan after 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 to be granted in the event an optionee surrenders
shares of common stock which the optionee already owns in full or partial
payment of the option price of an option being exercised and/or surrenders
shares of common stock to satisfy withholding tax obligations incident to the
exercise of an option. A restored option is for the number of shares
surrendered by the optionee and has an option price equal to the fair market
value of the common stock on the date on which the exercise of an option
resulted in the grant of the restored option.
96
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 an option must be exercised no later than ten years after
grant date.
Stock Compensation Plan for Non-Employee Directors - The ONEOK, Inc.
Stock Compensation Plan for Non-Employee Directors provides for the granting of
incentive stock bonus awards, performance unit awards, restricted stock awards,
and non-qualified stock options to Non-Employee Directors. The Company has
reserved 700,000 shares less the number of shares previously issued under the
plan. The maximum number of shares of common stock with respect to which
options or other awards may be granted to any Non-Employee Director during any
year is 20,000.
Under the plan, options may be granted by the Committee at any time on or
before January 18, 2011. Options may be exercisable in full at the time of
grant or may become exercisable in one or more 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 option price of an option being exercised and/or surrenders shares of
common stock to satisfy withholding tax obligations incident to the exercise of
an option. A restored option is for the number of shares surrendered by the
optionee, and has an option price equal to the fair market value of the common
stock on the date the exercise of an option resulted in the grant of the
restored option. Options issued to date become void upon termination of service
as a Non-Employee Director. Such options must be exercised no later than ten
years after the date of grant of the option. In the event of death, the option
may be exercised by the personal representative of the optionee.
97
Stock option activity has been restated to give effect to the 2001 two-for-one
stock split. Activity to date has been as follows:
Weighted
Number of Average
Shares Exercise Price
-----------------------------------------------------------------
Outstanding August 31, 1998 701,952 $ 15.65
Granted 531,448 $ 17.61
Exercised (55,900) $ 13.44
Expired (5,000) $ 17.45
Restored 71,690 $ 17.98
-----------------------------------------------------------------
Outstanding August 31, 1999 1,244,190 $ 16.55
Granted 617,400 $ 14.58
Exercised (2,000) $ 11.85
Expired (6,000) $ 17.61
Restored 1,726 $ 13.69
-----------------------------------------------------------------
Outstanding December 31, 1999 1,855,316 $ 15.89
Granted 8,000 $ 13.16
Exercised (342,822) $ 15.38
Expired (74,200) $ 16.01
Restored 55,062 $ 21.45
-----------------------------------------------------------------
Outstanding December 31, 2000 1,501,356 $ 16.19
Granted 1,102,000 $ 22.43
Exercised (118,750) $ 15.27
Expired (179,672) $ 19.57
Restored 3,538 $ 22.49
-----------------------------------------------------------------
Outstanding December 31, 2001 2,308,472 $ 18.96
=================================================================
Options Exercisable
-----------------------------------------------------------------
August 31, 1999 709,990 $ 15.75
December 31, 1999 841,540 $ 16.05
December 31, 2000 813,894 $ 16.27
December 31, 2001 941,572 $ 16.57
-----------------------------------------------------------------
At December 31, 2001, the Company had 1,157,952 outstanding options with
exercise prices ranging between $11.85 to $17.78 and a weighted average
remaining life of 7.02 years. Of these options, 803,252 were exercisable at
December 31, 2001 with a weighted average exercise price of $16.04.
The Company also had 1,150,520 options outstanding at December 31, 2001 with
exercise prices ranging between $17.78 and $26.67 and a weighted average
remaining life of 8.62 years. Of these options, 138,320 were exercisable at
December 31, 2001 at a weighted average exercise price of $19.64.
Restricted Stock Awards - Under the Long-Term Incentive Plan, 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
shareholders' 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 $22.31 and
$13.16 for the years ended December 31, 2001 and 2000, respectively.
98
Restricted stock information has been restated to give effect to the 2001
two-for-one stock split. Restricted stock activity to date is as follows:
Number of
Shares
----------------------------------------
Outstanding August 31, 1999 -
Granted 132,600
Released to participants -
Forfeited -
Dividends 1,394
----------------------------------------
Outstanding December 31,1999 133,994
Granted 4,000
Released to participants (7,848)
Forfeited (20,780)
Dividends 5,448
----------------------------------------
Outstanding December 31, 2000 114,814
Granted 90,400
Released to participants (2,424)
Forfeited (6,676)
Dividends 6,463
----------------------------------------
Outstanding December 31, 2001 202,577
========================================
Employee Stock Purchase Plan - In 1995, the Company authorized the Employee
Stock Purchase Plan (ESPP) and the Company currently has 2.8 million shares
reserved for the ESPP less the number of shares issued to date under this plan.
Subject to certain exclusions, 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 grant date or exercise date market price. Approximately 56
percent, 56 percent, and 54 percent of eligible employees participated in the
plan in fiscal years 2001, 2000, and 1999, respectively. Under the plan, the
Company sold 192,593 shares in fiscal year 2001, 523,044 shares in fiscal year
2000, and 176,058 shares in fiscal year 1999.
Accounting Treatment - The Company continues to apply APB 25 in accounting for
both plans. Accordingly, no compensation cost 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 Statement 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 Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------------
Net Income (Thousands of dollars, except per share amounts)
As reported $ 101,565 $ 145,607 $ 35,344 $ 106,357
Pro Forma $ 85,415 $ 135,893 $ 27,066 $ 99,887
Earnings per share - Diluted
As reported $ 0.85 $ 1.23 $ 0.27 $ 0.86
Pro Forma $ 0.71 $ 1.15 $ 0.20 $ 0.81
=====================================================================================================
99
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 0.2309 for fiscal year 2001, 0.2406 for fiscal year 2000,
0.2414 for the four months ended December 31, 1999, and 0.2151 for the year
ended August 31, 1999. The average dividend amount is estimated to be $0.615
per share for fiscal year 2001, $0.61 per share for fiscal year 2000, the four
months ended December 31, 1999, and the year ended August 31, 1999, with a
risk-free interest rate of 5.497 percent of fiscal year 2001, 5.665 percent for
fiscal year 2000, 5.664 percent for the four months ended December 31, 1999,
and 5.983 percent for the year ended August 31, 1999.
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 at fair market value
under the Plan were $8.14 and $13.29 for the years ended December 31, 2001 and
2000, respectively, $11.52 for the four months ended December 31, 1999, and
$13.86 for the year ended August 31, 1999. Fair value of options granted above
fair market value under the Plan was $7.92 for the year ended December 31,
2001. The average exercise price of options granted above fair market value is
$23.49 for the year ended December 31, 2001.
(Q) EARNINGS PER SHARE INFORMATION
The following is a reconciliation of the basic and diluted EPS computations.
Year Ended December 31, 2001
Per Share
Income Share Amount
---------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 64,465 59,557
Convertible preferred stock 37,100 39,892
--------------------------
Income available for common stock
and assumed conversion of preferred stock 101,565 99,449 $ 1.02
==========================
Further dilution from applying the "two-
class" method (0.17)
---------
Basic earnings per share $ 0.85
=========
Effect of Other Dilutive Securities
Options - 222
--------------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 101,565 99,671 $ 1.02
==========================
Further dilution from applying the "two-
class" method (0.17)
---------
Diluted earnings per share $ 0.85
=======================================================================================
100
Year Ended December 31, 2000
Per Share
Income Share Amount
----------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 108,507 58,448
Convertible preferred stock 37,100 39,892
--------------------------
Income available for common stock
and assumed conversion of preferred stock 145,607 98,340 $ 1.48
==========================
Further dilution from applying the "two-
class" method (0.25)
---------
Basic earnings per share $ 1.23
=========
Effect of Other Dilutive Securities
Options - 48
--------------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 145,607 98,388 $ 1.48
==========================
Further dilution from applying the "two-
class" method (0.25)
---------
Diluted earnings per share $ 1.23
=======================================================================================
Four Months Ended December 31, 1999
Per Share
Income Share Amount
---------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 22,977 60,850
Convertible preferred stock 12,367 39,892
--------------------------
Income available for common stock
and assumed conversion of preferred stock 35,344 100,742 $ 0.35
==========================
Further dilution from applying the "two-
class" method (0.08)
---------
Basic earnings per share $ 0.27
=========
Effect of Other Dilutive Securities
Options - 26
--------------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 35,344 100,768 $ 0.35
==========================
Further dilution from applying the "two-
class" method (0.08)
---------
Diluted earnings per share $ 0.27
=======================================================================================
101
Year Ended August 31, 1999
Per Share
Income Share Amount
=======================================================================================
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 69,110 62,996
Convertible preferred stock 37,247 40,106
--------------------------
Income available for common stock
and assumed conversion of preferred stock 106,357 103,102 $ 1.03
==========================
Further dilution from applying the "two-
class" method (0.17)
---------
Basic earnings per share $ 0.86
=========
Effect of Other Dilutive Securities
Options - 40
--------------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 106,357 103,142 $ 1.03
==========================
Further dilution from applying the "two-
class" method (0.17)
---------
Diluted earnings per share $ 0.86
=======================================================================================
There were 158,989, 113,836, 180,010, and 82,070 option shares excluded from
the calculation of Diluted Earnings per Share for the years ended December 31,
2001 and 2000, the four months ended December 31, 1999, and the year ended
August 31, 1999, 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 Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------
Basic EPS (Per share amounts)
Income available for common stock
before cumulative effect of a
change in accounting principle $ 0.87 $ 1.21 $ 0.27 $ 0.86
Cumulative effect of a change in
accounting principle, net of tax (0.02) 0.02 - -
------------ ------------ ------------ ------------
Income available for common stock $ 0.85 $ 1.23 $ 0.27 $ 0.86
Diluted EPS
Income available for common stock
before cumulative effect of a
change in accounting principle $ 0.87 $ 1.21 $ 0.27 $ 0.86
Cumulative effect of a change in
accounting principle, net of tax (0.02) 0.02 - -
------------ ------------ ------------ ------------
Income available for common stock $ 0.85 $ 1.23 $ 0.27 $ 0.86
===============================================================================================
102
(R) OIL AND GAS PRODUCING ACTIVITIES
The following is historical cost information relating to the Company's
production operations:
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Capitalized costs at end of year
Unproved properties $ 4,223 $ 2,210 $ 4,224 $ 4,245
Proved properties 475,151 423,824 398,748 393,096
-----------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 479,374 426,034 402,972 397,341
Accumulated depreciation, depletion and amortization 177,622 146,749 128,220 120,109
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 301,752 $ 279,285 $ 274,752 $ 277,232
===================================================================================================================================
Costs incurred during the year
Property acquisition costs (unproved) $ 2,334 $ 878 $ 103 $ 948
Exploitation costs $ 8 $ 10 $ 6 $ 17
Development costs $ 53,220 $ 32,817 $ 6,254 $ 13,659
Purchase of minerals in place $ 1,572 $ 4,751 $ - $ 79,385
-----------------------------------------------------------------------------------------------------------------------------------
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 Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
-------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net revenues
Sales to unaffiliated customers $ 93,935 $ 49,868 $ 18,623 $ 42,077
Gas sold to affiliates 26,173 19,669 4,779 22,868
--------------------------------------------------------------------------------------------------------------------------
Net revenues from production 120,108 69,537 23,402 64,945
--------------------------------------------------------------------------------------------------------------------------
Production costs 20,991 17,575 5,465 14,516
Exploitation costs 8 10 6 17
Depreciation, depletion and amortization 35,017 30,465 9,588 33,771
Income taxes 24,999 8,311 3,226 6,359
-------------------------------------------------------------------------------------------------------------------------
Total expenses 81,015 56,361 18,285 54,663
-------------------------------------------------------------------------------------------------------------------------
Results of operations from producing activities $ 39,093 $ 13,176 $ 5,117 $ 10,282
==========================================================================================================================
(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 years 2001, 2000, the four
months ended December 31, 1999, and the year ended August 31,1999.
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 both
internally and by an independent reserve engineer and revised, either upward or
downward, as warranted by additional performance data.
103
Oil Gas
(MBbls) (MMcf)
-------------------------------------------------------------------
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
Revisions in prior estimates (536) (28,233)
Extensions, discoveries and other additions 1,198 33,397
Purchases of minerals in place 3 936
Sales of minerals in place - (276)
Production (493) (27,578)
------------------------------------------------------------------
December 31, 2001 4,511 232,967
==================================================================
Proved developed reserves
August 31, 1999 2,540 175,771
December 31, 1999 2,451 169,060
December 31, 2000 2,495 182,052
December 31, 2001 2,723 161,725
------------------------------------------------------------------
(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 are shown in the following table.
104
Year Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Future cash inflows $ 669,328 $ 2,498,525 $ 632,751 $ 639,721
Future production and development costs 200,741 400,767 194,332 194,077
Future income taxes 119,864 742,505 62,533 53,442
------------------------------------------------------------------------------------------------------------------------
Future net cash flows 348,723 1,355,253 375,886 392,202
10 percent annual discount for estimated
timing of cash flows 149,101 599,370 149,527 161,156
------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash
flows relating to oil and gas reserves $ 199,622 $ 755,883 $ 226,359 $ 231,046
=========================================================================================================================
Future cash inflows are computed by applying year-end prices (averaging $19.84
per barrel of oil, adjusted for transportation and other charges, and $2.49 per
Mcf of gas at December 31, 2001) to the year-end quantities of proved reserves.
As of December 31, 2001, a portion of proved developed gas production in 2002
has been hedged. The effects 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 Year Four Months Year
Ended Ended Ended Ended
December 31, December 31, December 31, August 31,
2001 2000 1999 1999
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Beginning of period $ 755,883 $ 226,359 $ 231,046 $ 162,629
Changes resulting from:
Sales of oil and gas produced, net of production costs (99,117) (51,962) (17,938) (50,120)
Net changes in price, development, and production costs (825,483) 783,763 3,523 13,269
Extensions, discoveries, additions, and improved
recovery, less related costs 50,353 102,607 9,981 37,379
Purchases of minerals in place 1,572 4,751 - 67,120
Sales of minerals in place (2,247) (5,761) (24) (9,326)
Revisions of previous quantity estimates (136,171) 43,318 (8,454) 10,477
Accretion of discount 116,776 25,826 8,750 17,317
Net change in income taxes 345,485 (376,438) (6,174) (11,618)
Other, net (7,429) 3,420 5,649 (6,081)
----------------------------------------------------------------------------------------------------------------------
End of period $ 199,622 $ 755,883 $ 226,359 $ 231,046
======================================================================================================================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
105
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
2002 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 2002 definitive Proxy Statement which is incorporated
herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is shown in the 2002 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 2002 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 2002 definitive Proxy Statement which is incorporated herein
by this reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on certain relationships and related transactions is shown in the
2002 definitive Proxy Statement, which is incorporated herein by this reference.
106
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, Commission File No. 333-27467).
(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 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) Amendment to Certificate of Incorporation of ONEOK, Inc. filed May
23, 2001 (Incorporated by reference from Exhibit 4.15 to
Registration Statement on Form S-3 filed July 18, 2001,
Commission File No. 333-65392).
(3)(g) 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)(h) 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) 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, Commission File No.
333-27467).
(4)(b) Certificate of Designation for Series C Participating Preferred
Stock of ONEOK, Inc., filed November 26, 1997 (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)(c) 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, Commission File No. 333-27467).
(4)(d) 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, Commission File No. 333-27467).
(4)(e) Indenture, dated September 24, 1998, between ONEOK, Inc. and
Chase Bank of Texas
107
(Incorporated by reference from Exhibit 4.1 to Registration
Statement on Form S-3 filed August 26, 1998).
(4)(f) Indenture dated December 28, 2001, between ONEOK, Inc. and
SunTrust Bank (Incorporated by reference Exhibit 4.1 to
Post-Effective Amendment No. 1 to Registration Statement on Form
S-3 filed December 31, 2001).
(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, Commission File No. 333-76375).
(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,
Commission File No. 333-32254).
(4)(m) Seventh Supplemental Indenture dated April 24, 2000, between
ONEOK, Inc. and Chase Bank of Texas (Incorporated by reference
from Exhibit 4 to the Company's current report on Form 8-K filed
April 24, 2000).
(4)(n) Eighth Supplemental Indenture dated April 6, 2001, between ONEOK,
Inc. and The Chase Manhattan Bank (Incorporated by reference
from Exhibit 4.9 to Registration Statement on Form S-3 filed
July 18, 2001, Commission File No. 333-65392).
(10)(a) ONEOK, Inc. Long-Term Incentive Plan
(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 February 21, 2002.
(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) ONEOK, Inc. Annual Officer Incentive Plan
108
(10)(g) ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan,
as amended and restated February 15, 2001
(10)(h) 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)(i) 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)(j) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May
15, 1983 (Incorporated by reference from Form 10-K dated August
31, 1983).
(10)(k) 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)(l) 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)(m) 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)(n) 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)(o) $850,000,000 364-Day Credit Agreement dated June 28, 2001, among
ONEOK, Inc., Bank of America, N.A., as Administrative Agent and
as a Lender, Letter of Credit Issuer and Swing Line Lender, Bank
One, N.A. and First Union National Bank as Co-Syndicate Agents
and ABN Amro Bank N.V. and Fleet National Bank as
Co-Documentation Agents (Incorporated by reference from Form
10-Q dated June 30, 2001)
(12)(a) Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirement for the years ended
December 31, 2001 and 2000.
(12)(b) Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirement for the four months ended
December 31, 1999 and 1998 (Incorporated by reference from Form
10-K dated December 31, 2000).
(12)(c) Computation of Ratio of Earnings to Fixed Charges for the years
ended December 31, 2001 and 2000.
(12)(d) Computation of Ratio of Earnings to Fixed Charges for the four
months ended December 31, 1999 and 1998 (Incorporated by
reference from Form 10-K dated December 31, 2000).
(21) Required information concerning the registrant's subsidiaries.
(23) Independent Auditors' Consent
(99)(a) ONEOK, Inc. Direct Stock Purchase and Dividend Reinvestment Plan
(Incorporated by reference from the Form S-3 filed January 30,
2001).
109
(2) Financial Statements Page No.
(a) Independent Auditors' Report. 64
(b) Consolidated Statements of Income for the years ended 65
December 31, 2001 and 2000, August 31, 1999 and the
four months ended December 31, 1999.
(c) Consolidated Balance Sheets at December 31, 2001, 2000 66-67
and 1999.
(d) Consolidated Statements of Cash Flows for the years 68
ended December 31, 2001 and 2000, August 31, 1999
and the four months ended December 31, 1999.
(e) Consolidated Statements of Shareholders' Equity for the 69-70
years ended December 31, 2001 and 2000, August 31,
1999 and the four months ended December 31, 1999.
(f) Notes to Consolidated Financial Statements. 71-105
(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
November 14, 2001 - Filed the transcript of the conference call with
analysts to discuss third quarter earnings.
November 21, 2001 - Announced that the Company will ask the Oklahoma
Supreme court to overturn an Oklahoma Corporation Commission order that
unfairly denies the Company the right to collect $34.6 million in
outstanding gas costs incurred to serve customers last winter.
December 3, 2001 - Announced that the Company will take a charge of 18
cents per share of common stock in the fourth quarter as the result of an
order from the Oklahoma Corporation Commission that unfairly denies the
Company the right to collect outstanding gas costs incurred to serve
customers last winter.
December 3, 2001 - Announced that the Company's net exposure to Enron as
of November 29, 2001 was less than $40 million pre-tax.
December 21, 2001 - Announced revised earnings guidance for 2001.
January 8, 2002 - Announced that the federal district court ruled that
Southwest Gas Corporation cannot attempt to pursue its alleged $308
million claim against the Company.
January 18, 2002 - Announced that the Company had been granted a waiver on
a possible technical default related to various financing leases tied to
the Company's Bushton processing plant.
110
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 14th day of March
2002.
ONEOK, Inc.
Registrant
By: /s/Jim Kneale
-----------------------------------------
Jim Kneale
Senior Vice President, Treasurer and Chief
Financial Officer (Principal Financial
Officer)
111
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 14th day of
March 2002.
/s/ David L. Kyle /s/ Beverly Monnet
---------------------------- ------------------------------------
David L. Kyle Beverly Monnet
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/ John B. Dicus /s/ J.D. Scott
---------------------------- ------------------------------------
John B. Dicus J. D. Scott
Director Director
/s/ William L. Ford
---------------------------- ------------------------------------
William L. Ford Pattye L. Moore
Director Director
/s/ Douglas T. Lake
----------------------------
Douglas T. Lake
Director
112