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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
- --- ACT OF 1934 for the fiscal year ended August 31, 1997
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- --- EXCHANGE ACT OF 1934 for the transition period from to
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Commission file number 1-13643
ONEOK, INC.
(Exact name of registrant as specified in its charter)
OKLAHOMA 73-1520922
(State or other jurisdiction of ( I.R.S. Employer
incorporation or organization) Identification No.)
100 WEST FIFTH STREET, TULSA, OK 74103
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (918) 588-7000
ONEOK INC.
(Former name if changes since last report.)
Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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Common stock, with par value of $0.01 New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
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Aggregate market value of registrant's voting stock held by nonaffiliates as of
November 1, 1997, was: Common stock $948 million.
On November 1, 1997, the Company had 28,091,622 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
DOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement related to 1997 annual meeting. Part III
Form S-4 dated August 6, 1997, file number 33-27467.
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ONEOK INC.
1996 ANNUAL REPORT ON FORM 10-K
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PART I PAGE NO.
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Item 1. Business 3 - 10
Item 2. Properties 10 - 13
Item 3. Legal Proceedings 13 - 14
Item 4. Results of Votes of Security Holders 14 - 15
PART II
Item 5. Market Price and Dividends on the Registrant's
Common Stock and Related Shareholder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17 - 26
Item 8. Financial Statements and Supplementary Data 27 - 50
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 10. Directors, Executive Officers, Promoters, and
Control Persons of the Registrant 51
Item 11. Executive Compensation 51
Item 12. Security Ownership of Certain Beneficial Owners and Management 51
Item 13. Certain Relationships and Related Transactions 51
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 52
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PART I.
ITEM 1. BUSINESS
GENERAL - ONEOK Inc., a Delaware corporation, was organized in 1936. It is a
successor to a company founded in 1906 as Oklahoma Natural Gas Company. The
corporation's name was changed to ONEOK Inc. (pronounced one-oak) in 1980. ONEOK
Inc. and subsidiaries (collectively, the Company) is a diversified energy
company engaged in the production, gathering, storage, transportation,
distribution and marketing of environmentally clean fuels and products. The
Company's business units are characterized as operating within either a rate
regulated environment (regulated operations) or a nonregulated environment
(nonregulated operations).
The regulated business unit provides natural gas distribution and transmission
for about 75 percent of Oklahoma. These services are primarily conducted by
Oklahoma Natural Gas Company (a division of ONEOK) and two subsidiaries, ONG
Transmission Company and ONG Sayre Storage Company. These companies will be
collectively referred to herein as Oklahoma Natural Gas.
The nonregulated business unit includes the following core business segments:
natural gas marketing activities conducted by ONEOK Gas Marketing Company; gas
processing activities conducted primarily by ONEOK Products Company; and
production activities conducted by ONEOK Resources Company. Other businesses
include ONEOK Leasing Company and ONEOK Parking Company.
ACQUISITIONS AND MERGERS - Western Resources Inc. ("Western Resources"), WAI,
Inc. and the Company entered into an agreement dated December 12, 1996, as
restated as of May 19, 1997 (the "Agreement") providing for the transactions
(the "Transactions") described below. First, Western Resources transferred to
WAI, Inc., a new corporation formed by Western Resources, herein after known as
"New ONEOK" (i) all of the assets, property and interests owned by Western
Resources that are primarily used in, primarily related to or primarily
generated by the field operations of Western Resource's local natural gas
distribution business in the States of Kansas and Oklahoma, including: the gas
gathering, distribution and transmission system and related properties and
rights; (ii) all of the capital stock of Western Resources' wholly-owned
subsidiaries, Mid Continent Market Center, Inc. (MCMC) and Westar Gas Marketing,
Inc. and (iii) all of the debts, claims and liabilities that arise primarily out
of, relate primarily to or are primarily generated by, the field operations of
Western Resources' local natural gas distribution business in the States of
Kansas and Oklahoma (such liabilities and debts to include an aggregate
principal amount of debt of Western Resources of $35 million, subject to
adjustment) and of the wholly-owned subsidiaries.
Immediately thereafter, the Company merged with and into New ONEOK with New
ONEOK being the surviving corporation; New ONEOK then changed its name to ONEOK,
Inc. Each outstanding share of common stock of the Company was exchanged for one
share of New ONEOK Common Stock. Upon consummation of the merger, (i) the
current Company stockholders hold 27,304,870 shares of ONEOK, Inc. Common Stock,
representing 90.1 percent of the voting power and 55 percent of the capital
stock of ONEOK, Inc. and (ii) Western Resources holds 3,094,257 shares of ONEOK,
Inc. Common Stock, representing 9.9 percent of the voting power of ONEOK, Inc.,
and 19,946,448 shares of ONEOK, Inc. Preferred Stock, which shares will not be
entitled to vote in the election of directors, such shares of ONEOK, Inc. Common
Stock and ONEOK, Inc. Preferred Stock together representing in the aggregate up
to 45 percent of the capital stock of ONEOK, Inc.
Each share of ONEOK, Inc. Preferred Stock will be convertible at Western
Resources' option into one share of ONEOK, Inc. Common Stock, subject to
adjustment, following the occurrence of a "regulatory change," which is defined
in the shareholder agreement to be entered into by Western Resources and the
Company prior to the closing of the Transactions (the "Shareholder Agreement")
as (i) a repeal, modification, amendment or other change of the Public Utility
Holding Company Act of 1935 (the "1935 Act") and/or (ii) the receipt by Western
Resources of an exemption, unqualified opinion or no-action letter from the
Securities and Exchange Commission or its staff under the 1935 Act, or Western
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Resource's registration under the 1935 Act, either or both of which has the
result of permitting Western Resources to convert its shares of ONEOK, Inc.
Preferred Stock into ONEOK, Inc. Common Stock.
Upon such conversion, Western Resources will hold up to 45 percent of the then
outstanding shares of ONEOK, Inc. Common Stock. The Shareholder Agreement will
impose certain standstill, transfer and voting restrictions on Western Resources
with respect to its beneficial ownership of ONEOK, Inc. capital stock both
before and after the regulatory change and will entitle Western Resources to
designate a number of directors (not exceeding one-third of the entire Board) to
be nominated to the ONEOK, Inc. Board.
The Shareholders of the Company approved the Transactions at a special meeting
of shareholders held on September 25, 1997. The Oklahoma Corporation Commission
(OCC) approved the Transaction on September 10, 1997. Approval was received from
the Kansas Corporation Commission (KCC) in October 1997. The transaction was
consummated and effective November 26, 1997.
The description of the Transactions contained herein is qualified in its
entirety by reference to Form 8-K filed November 26, 1997, Amendment No. 3 to
Registration Statement on Form S-4 (combined proxy statement/prospectus)
registration no. 333-27467 as filed with the Securities and Exchange Commission
on August 6, 1997 which is incorporated herein by reference. The Agreement and
Shareholder Agreement are Appendix A and B respectively thereto.
The Company is interested in acquiring additional gas distribution and
transmission facilities which will further enhance its operations and continues
to pursue opportunities for acquisitions as they occur.
ENVIRONMENTAL MATTERS - The Company is subject to Federal, state, and local laws
and regulatory programs relating to the environment. These laws govern the
normal ongoing operations of the Company including the discharge of materials
into the environment or the protection of the environment. Ongoing environmental
compliance activities are integrated with the Company's regular operation and
maintenance activities. The Company is actively promoting the environmental
advantages of natural gas in comparison to other fuels including promoting the
use of natural gas in automobiles. Management believes that the increasing
concerns about the environment will result in an increased use of natural gas.
There have been no material effects upon capital expenditures, earnings, or the
Company's competitive position during the 1997 fiscal year related to compliance
with these regulations. No material effects of this nature are anticipated
during the 1998 fiscal year.
EMPLOYEES - The Company employed 1,800 persons at August 31, 1997, and is
currently not a party to any collective bargaining agreements with its
employees.
FINANCIAL AND STATISTICAL INFORMATION - For financial and statistical
information regarding the Company's business units by segment, see "
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note I of Notes to Consolidated Financial Statements.
The Company's regulated and nonregulated business units are discussed below.
(A) REGULATED OPERATIONS
GENERAL
Oklahoma Natural Gas Company and two regulated subsidiaries of ONEOK
comprise a fully integrated intrastate natural gas gathering, storage,
distribution and transmission business, which purchases, stores,
transports, and distributes natural gas for sale to wholesale and retail
customers located primarily in the state of Oklahoma. It also leases
pipeline capacity to industrial customers for their use in transporting
natural gas to their facilities. ONG Transmission Company transports gas
for others under Section 311(a) of the Natural Gas Policy Act of 1978
(NGPA). Oklahoma Natural Gas Company, ONG Transmission Company and ONG
Sayre Storage Company (Sayre) are consolidated for ratemaking purposes by
the OCC.
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Oklahoma Natural Gas purchases natural gas from gas processing plants,
producing gas wells, and pipeline suppliers, and utilizes five underground
storage facilities as necessary to deliver natural gas to approximately
733,600 customers at August 31, 1997, located in 296 communities in
Oklahoma. The Company's largest markets are the Oklahoma City and Tulsa
metropolitan areas. Oklahoma Natural Gas also sells natural gas and/or
leases pipeline capacity to other local gas distributors serving 46
Oklahoma communities. Oklahoma Natural Gas serves an estimated population
of over 2 million.
Oklahoma Natural Gas owns five underground gas storage facilities and
leases capacity to third parties on a short-term basis. The Sayre gas
storage facility is leased, on a long-term basis, to and operated by the
Natural Gas Pipeline Company of America. Sayre retains capacity for its
use.
Of the Company's consolidated revenues, revenue from the regulated
operations represented approximately 51.5, 44.0, and 62.3 percent for 1997,
1996, and 1995, respectively. Operating income before interest and taxes
from the regulated operations is 78.0, 80.4, and 86.8 percent of the
consolidated operating income before interest and taxes for 1997, 1996, and
1995, respectively.
GAS SUPPLY
Gas supplies available to Oklahoma Natural Gas for purchase and resale
include supplies of gas under both short and long-term contracts with
independent producers as well as pipeline companies, gas processors and
other suppliers that own or control reserves. Oklahoma is the third largest
gas producing state in the nation; and Oklahoma Natural Gas, unlike most
utilities, has direct access through its transmission system to all of the
major gas producing areas in the state. The system, which intersects with
nine interstate pipelines at 26 interconnect points, 38 gas processing
plants and 128 producing fields located in Oklahoma, allows natural gas to
be moved to locations throughout the state and the nation. In addition,
four of the storage facilities operated by Oklahoma Natural Gas are located
in close proximity to its large market areas. These four storages have a
combined average capacity of 119 billion cubic feet to help assure
deliverability to customers even on winter peak usage days. On such days,
withdrawal from storage can provide as much as 50 percent of the system's
needs. The record for all-time peak gas deliveries through the system in a
single day was 1.92 billion cubic feet.
The Oklahoma Natural Gas rate schedules contain an "Order of Curtailment"
that provides for first reducing or totally discontinuing gas service to
the very large industrial users and graduating down to requesting
residential and commercial customers to reduce their gas requirements to an
amount essential for public health and safety.
The Company has a surplus of natural gas available to its utility system
and does not anticipate any problem with securing additional gas supply as
needed for its customers for the foreseeable future.
CUSTOMERS
RESIDENTIAL AND COMMERCIAL - Oklahoma Natural Gas distributes natural gas
as a public utility to approximately 75 percent of Oklahoma. Natural gas
sales to residential and commercial customers, which is used primarily for
heating and cooking, accounts for approximately 60 and 26 percent of gas
sales, respectively. Gas sales to residential and commercial customers are
seasonal, as a substantial portion of such sales are used principally for
space heating. Accordingly, the volume of gas sales is consistently higher
during the heating season (November through May) than in other months of
the year. Rates for natural gas distribution operations include a
temperature normalization adjustment clause during the heating season.
Oklahoma Natural Gas holds franchises, all of which are for an initial
period of 25 years, in the major municipalities in which it operates. In
the state of Oklahoma, a franchise is a right to use the municipal streets,
alleys, and other public ways for utility facilities for a defined period
of time for a fee. Although the laws of the state of Oklahoma prohibit
exclusive utility franchises, management nevertheless believes there are
advantages to having franchises in the larger municipalities in which
operations are conducted. Seventeen municipalities with a population of
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over 10,000 in which franchises are held, have an aggregate population
representing approximately 1.2 million. Oklahoma Natural Gas has franchises
or gross receipts agreements in 219 other municipalities in which there is
an aggregate population of approximately 640,000. In management's opinion,
its franchises contain no unduly burdensome restrictions and are sufficient
for the transaction of business in the manner in which it is now conducted.
INDUSTRIAL - A substantial portion of the system throughput is transported
for industrial customers, in particular, several large fertilizer plants
which use natural gas as feedstock. Certain interstate and intrastate
pipeline companies have continued to be very aggressive in attempting to
capture industrial load within the Oklahoma Natural Gas service area, a
phenomenon generally referred to in the gas industry as "bypass." Oklahoma
Natural Gas has minimized the negative impact of bypass practices through
its Pipeline Capacity Lease (PCL) and Special Industrial Sales programs
(SISP). The PCL program enables the customer, for a fee, to have its gas
transported to its facilities utilizing lines owned by Oklahoma Natural
Gas. PCL services are at rates substantially below the industrial tariff
rates. In 1995, the OCC allowed rates for large industrial customers to be
restructured and reduced. Under this new structure, tariffs are established
setting forth the maximum rates and a standard form of PCL agreement,
subject to changes in the agreement as may be negotiated by Oklahoma
Natural Gas and the customer. The SISP program allocates lower cost
supplies to these customers if they choose to purchase their gas from
Oklahoma Natural Gas.
Industrial sales, rentals for PCLs, and other energy-related operations
tend to remain relatively constant throughout the year, while interstate
transportation volumes fluctuate based on market demand. Revenues from
fertilizer plant customers continue to decline as a percentage of total
revenues as a result of the rate restructuring noted at "Government
Regulations" and as a result of bypass. No single customer accounted for
more than 10 percent of the Company's total operating revenues.
The potential impact of the loss of a significant portion of this volume is
discussed at Management's Discussion and Analysis of Financial Condition
and Results of Operations, Liquidity, on page 26.
During the current year, the Company commenced construction of four
pipelines representing its most extensive pipeline construction project in
recent history. Two of the four pipelines have been completed. The
remaining two pipelines are scheduled for completion by January 1998. Upon
completion, these pipelines will begin transporting gas to four natural
gas-fired electric generating plants owned by Public Service Company of
Oklahoma. The gas will be supplied by the Company's gas marketing
operation.
COMPETITION
The natural gas industry is expected to remain highly competitive.
Management believes that it must maintain a competitive advantage in order
to retain its customers and, accordingly, continues to focus on reducing
costs and pursuing unbundling opportunities.
Oklahoma Natural Gas is subject to competition from electric utilities
offering electricity as a rival energy source and competing for the space
heating, water heating, and cooking markets. The principal means to compete
against alternative fuels is lower prices, and natural gas continues to
maintain its price advantage in the residential, commercial, and both small
and large industrial markets. Compared to electricity for water heating,
cooking or space heating, natural gas service provided by Oklahoma Natural
Gas is 56 percent, 39 percent and 72 percent less expensive. Oklahoma
Natural Gas rates are competitive nationally. In residential markets, the
average cost of 10 Mcf is $53.43 for Oklahoma Natural Gas customers versus
$61.68 for the average cost nationwide.
Oklahoma Natural Gas is subject to competition from other pipelines for its
existing industrial load. The PCL program and SISP programs are a response
to such competitive pressure. The PCL rate
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structure allows Oklahoma Natural Gas to effectively compete in these
markets and maintain throughput and, therefore, load factors which benefit
all customer classes.
In April 1992, the Federal Energy Regulatory Commission (FERC) approved
Order 636. Less than one percent of Oklahoma Natural Gas's gas supply is
transported on interstate pipelines; Order 636 has had little impact on the
Company's operations.
Increasing competition in the natural gas industry along with the efforts
of the OCC to restructure the state's gas utility industry have been
driving forces behind the Company's plans to unbundle its services. The
Company is working closely with the OCC in order to develop a plan that is
both fair and sufficiently flexible to accommodate necessary future
changes.
GOVERNMENT REGULATIONS
Rates charged for gas services, including distribution, transmission and
storage, are established by the OCC and include a purchased gas adjustment
clause that allows changes in gas purchase costs to be passed on to various
classes of customers. Other costs must be recovered through periodic rate
adjustments approved by the OCC.
The Company has previously settled all known claims arising out of
long-term gas supply contracts containing "take-or-pay" provisions which
purported 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 period of 20 years or approximately
$6.7 million annually through a combination of a surcharge from customers
and revenue from transportation under Section 311(a) of the NGPA and other
intrastate transportation revenues. There are no significant potential
claims or cases pending against the Company under remaining gas purchase
contracts.
In a 1995 rate order, Oklahoma Natural Gas received a $13.8 million
permanent increase in base rates and an additional $1.15 million increase
for two years. Rates for large industrial customers were restructured and
reduced, with the revenue reduction shifted to core residential and
commercial customers. Changes to purchasing and pricing practices provided
a decrease in the cost of gas that more than offset the impact of the rate
increase, allowing core customers a net savings in rates. A temperature
adjustment clause included in the order reduced the effect of extremes in
weather for both the Company and the customer. Also included in the order
was an agreement not to file for a general rate increase for two years. In
connection with the Western alliance, the Company has filed a stipulation
which includes an agreement not to file for a rate increase for a period of
one year. Order No. 416480 from the OCC dated October 3rd, 1997, confirmed
that stipulation.
OTHER REGULATED BUSINESSES
The Company owns assets in Texas which are regulated by the Texas Railroad
Commission and are leased to Red River Pipeline Company under a long term
lease. During the first quarter of fiscal 1998, these assets will be
exchanged for transmission and compression facilities in Oklahoma.
OkTex Pipeline Company transports gas in interstate commerce under Section
311(a) of the NGPA and is treated as a separate entity by the Federal
Energy Regulatory Commission (FERC). The Company has the capacity to move
up to 200 million cubic feet of gas per day into Lone Star Gas Company's
system in Texas and the Red River Pipeline. OkTex has complied with the
requirements of Order 636.
(B) NONREGULATED OPERATIONS
MARKETING
GENERAL - The Company's marketing operation purchases and markets natural
gas, primarily in the mid-continent area of the United States. Due to
expanded supply and storage capabilities, the marketing operation has
evolved from an intrastate aggregator into a interstate aggregator.
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Of the Company's consolidated operating revenues, revenue from the gas
marketing business represented approximately 39.6, 48.9, and 27.9 percent
for 1997, 1996, and 1995, respectively. Operating income before interest
and taxes from the marketing operation is 6.1, 10.7, and 4.5 percent of the
consolidated operating income before interest and taxes for 1997, 1996, and
1995, respectively.
MARKET CONDITIONS - The baseload marketing business is very competitive
and, as the industry matures, continues to go through a period of
consolidation and reduced margins. The Company's strategy is to concentrate
its efforts on capitalizing on day to day pricing volatility through the
use of gas storage facilities, hedging, and transportation arbitraging.
Management believes that its location in Oklahoma, as well as the benefits
derived from vertically integrating the gas marketing operations with the
Company's production, gathering, processing, storage and transportation
businesses, will provide the strategic advantage necessary to compete.
NEW PRODUCTS AND SERVICES - The marketing operation was the successful
bidder in a proposal to provide firm and interruptible gas service to
several natural gas-fired electric generating plants owned by Public
Service Company of Oklahoma. The regulated operation is constructing the
pipelines to serve these plants and will be transporting the gas under a
PCL agreement.
PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising
from fluctuations in both the market price and transportation costs of
natural gas, the Company routinely enters into natural gas futures, swaps
and options as a method of protecting its margins on the underlying
physical transactions. However, net open positions in terms of price,
volume and specified delivery point do occur.
PROCESSING
GENERAL - The Company's processing operation owns nonoperating interests in
15 gas processing plants in 11 plant locations. Currently, 12 plants are in
operation and several are running near or at capacity. The gas processing
operations include the extraction of natural gas liquids (NGLs) and the
separation ("fractionation") of mixed NGLs into component products (eg.,
ethane/propane mix, propane, iso and normal butane and natural gasoline).
The component products are used for petrochemical feedstock, residential
heating and cooking in rural areas, and blending into motor fuels. The
industry as a whole operates substantial numbers of such plants, many owned
by large integrated oil and gas companies and independents. NGL margins
have been highly volatile over the past several years as profitability is
dependent on the relationship between natural gas costs and NGL prices.
Management believes that the industry is becoming much more competitive as
demand increases for NGLs, especially petrochemical feedstock.
Extraction is the process of removing NGLs from the inlet raw gas stream,
thereby reducing the Btu content and volume (referred to as "shrinkage").
In addition, some gas from the gas stream is consumed as fuel during the
processing. The production costs of such liquids generally depend on the
cost of the natural gas being processed and the underlying agreements. The
Company compensates its gas suppliers for fuel and shrinkage costs in one
of two ways, either by returning a percentage of the proceeds from the
extracted NGLs to the supplier (a "percent of proceeds" contract) or by
replacing an equivalent amount of gas (a "fuel and shrink" contract). Due
to the volatility of the natural gas and NGL prices, "percent of proceeds"
contracts generally provide a more stable cash flow. At August 31, 1997,
the Company's processing plants are operating with 69 percent "fuel and
shrink" and 31 percent "percent of proceeds" contracts. Effective with the
closing of the alliance with Western the "percent of proceeds" contracts
will increase to 43 percent while the "fuel and shrink" contracts will
decrease to 57 percent.
Of the Company's consolidated operating revenues, revenue from the gas
processing business represented approximately 6.2, 4.8, and 6.8 percent for
1997, 1996, and 1995, respectively. Operating income before interest and
taxes for the processing operation is 10.0, 7.4, and 6.0 percent of the
consolidated operating income before interest and taxes for 1997, 1996, and
1995, respectively.
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PROCESSING CAPABILITIES - Recent developments include the expansion of
plant gathering systems into new areas of production and the development of
producer alliances bringing plants closer to capacity. Future strategies
include the relocation of under-utilized processing plants to new
production areas, the expansion of existing capabilities and growth through
acquisition of additional plants and gathering systems. During 1996, the
Company acquired an 8 percent interest in the Indian Basin Gas Processing
Plant in New Mexico. As part of the strategic alliance with Western, the
Company will acquire one additional plant and will increase its ownership
in Indian Basin to 42 percent.
Because of the generally favorable location of the plants and terms of the
Company's processing and operating agreements, management anticipates that
its current competitive position in processing will remain so for the near
future.
PRODUCTION
GENERAL - The Company's production operation strategy is to concentrate
ownership of hydrocarbon reserves in its service territory in order to add
value not only to its existing production operations but also to integrate
the processing, marketing, transmission, gathering, and storage businesses.
As a result, the Company is focusing its efforts on exploitation
activities.
Of the Company's consolidated operating revenues, revenue from the
production business represented approximately 2.3, 2.1, and 2.5 percent for
1997, 1996, and 1995, respectively. Operating income before interest and
taxes for the production operation is 6.8, 2.3, and 3.4 percent of the
consolidated operating income before interest and taxes for 1997, 1996, and
1995, respectively.
PRODUCING RESERVES - Natural gas is the primary focus of the Company's
production activities. As of August 31, 1997, the Company had working
interests in 923 gas wells and 233 oil wells located primarily in Oklahoma
and Louisiana. A number of these wells produce from multiple zones.
During 1997, the Company purchased PSEC, Inc., an independent oil and gas
producing company. This acquisition included 180 wells with proven reserves
of 20 Bcf of natural gas and 167,000 barrels of oil concentrated in three
counties in Oklahoma. The acquisition also included PSPC, Ltd., which
operates and owns a 42 percent interest in the Sycamore Gas Gathering
System.
During 1996, the Company purchased substantially all of the Oklahoma oil
and natural gas properties of SCANA Petroleum Resources. The $43.1 million
purchase included over 500 producing properties of which 90 percent are
natural gas. Also in 1996, the Company sold all of its oil and gas
producing properties in Alabama and Mississippi for approximately $18.9
million.
MARKET CONDITIONS - The goal of the Company is to develop an economically
viable reserve base through acquisition and development. Additionally, the
Company plans to become more active as an operator. 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,
like the rest of the industry, has occasionally curtailed some of its
natural gas production because of low prices. Most production is sold to
brokers at spot-market prices.
RISK MANAGEMENT - During 1997, the Company's production segment increased
its utilization of derivatives in order to hedge anticipated sales of oil
and natural gas production. These anticipated transactions have been hedged
with commodity swaps agreements whereby the Company is able to set the
price to be received for the future production and thus eliminate the risk
of declining market prices between the origination date of the swap and the
month of production. The Company's strategy in hedging anticipated
transactions is to eliminate the variability in earnings of its production
segment as a result of market fluctuations. To the extent that management
does not terminate a hedge or enter into an opposing derivative, the
current strategy will limit the potential gains which could result from
increases in market prices above the level set by the hedge.
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OTHER BUSINESSES
The Company, through two subsidiaries, owns a parking garage and leases an
office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, in which the
Company's headquarters is located. The parking garage is owned and operated
by ONEOK Parking Company. ONEOK Leasing Company leases excess office space
to others. Almost all downtown Tulsa Class A office space is rented and
very little Class A office space is available city-wide. As a result, Class
A rental rates are increasing.
ITEM 2. PROPERTIES
(A) DESCRIPTION OF PROPERTY
REGULATED
DISTRIBUTION - The Company owned 14,852 miles of pipeline and other
distribution facilities in Oklahoma at August 31, 1997. The Company owns a
five-story office building in Oklahoma City, Oklahoma, as well as a number
of warehouses, garages, meter and regulator houses, service buildings, and
other buildings throughout the state. The Company also owns a fleet of
vehicles and maintains an inventory of spare parts, equipment, and
supplies. In addition, the Company owns five underground storage facilities
located throughout the state. Four of the storage facilities operated by
the Company are located in close proximity to its large market areas. These
four storages have a combined average storage capacity of 119 billion cubic
feet. The other storage facility is located in western Oklahoma and is
leased to and operated by another company. However, 21.4 billion cubic feet
of storage capacity, in that facility, has been retained for use by the
Company.
TRANSMISSION - The Company owned a combined total of 3,819 miles of
transmission and gathering pipeline in Oklahoma at August 31, 1997.
Compression and dehydration facilities are located at various points
throughout the pipeline system.
Transmission and compression facilities located in Texas and leased to the
Red River Pipeline Company will be exchanged for transmission and
compression facilities in Oklahoma during first fiscal quarter of 1998.
PRODUCTION
The Company owns varying economic interests, including overriding royalty
interests, in 923 gas wells and 233 oil wells, some of which are multiple
completions. Such interests are in wells located primarily in Louisiana and
Oklahoma. The Company owns 76,617 net onshore developed leasehold acres and
14,312 net onshore undeveloped acres, located primarily in Louisiana,
Oklahoma, and Texas. The Company owns no offshore acreage.
Lease acreage in producing units is held by production. Leases not being
held by production are generally for a term of three years and require
payments of annual rentals.
PROCESSING
The Company owns interests in 15 gas processing plants at 11 plant
locations which extract liquid hydrocarbons from natural gas. All are
located in Oklahoma with the exception of one plant located in New Mexico.
The Company's share of the total plant capacity of 1,070 million cubic feet
per day is 327 million cubic feet per day.
OTHER
The Company owns a parking garage and land, subject to a long-term ground
lease expiring in year 2009 with six five-year extensions available, upon
which has been constructed a seventeen-story office building with
approximately 517,000 square feet of net rentable space. The office
building is being leased to the Company at a lease term of 25 years with
six five-year renewal options. After any renewal period, the Company can
purchase the property at its fair market value. The Company has occupied
and reserved approximately 220,000 square feet of space for its own use and
leases the remaining space to others.
10
<PAGE> 11
(B) OTHER INFORMATION
Oil and gas production is defined by the Securities and Exchange Commission
(SEC) to include natural gas liquids in their natural state. The Company's
processing operation produces a substantial amount of natural gas liquids
as a result of ownership in several gas processing plants, but the Company
does not own the reserves attributable to the gas processed by these
plants. The SEC excludes the production of natural gas liquids resulting
from the operation 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 operation.
OIL AND GAS RESERVES
All of the oil and gas reserves are located in the United States.
QUANTITIES OF OIL AND GAS RESERVES - See Note L of Notes to Consolidated
Financial Statements on page 46.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES - See Note M of Notes to
Consolidated Financial Statements on page 46 and 47.
RESERVE ESTIMATES FILED WITH OTHERS
None.
QUANTITIES OF OIL AND GAS PRODUCED
The net quantities of oil and natural gas produced and sold, including
intercompany transactions, were as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
SALES 1997 1996 1995
------------------------------------------------------------------------
<S> <C> <C> <C>
Oil (MBbls) 336 435 466
Gas (MMcf) 14,565 9,406 8,775
------------------------------------------------------------------------
</TABLE>
AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS
Average sales prices and lifting costs are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
1997 1996 1995
------------------------------------------------------------------------
<S> <C> <C> <C>
Average Sales Price (a)
Per Bbl of oil $19.84 $17.73 $16.22
Per Mcf of gas $2.16 $1.86 $1.51
Average Production Costs
Per Mcfe (b) $0.48 $0.46 $0.37
------------------------------------------------------------------------
</TABLE>
(a) In determining the average sales prices of oil and gas, sales to
affiliated companies were recorded on the same basis as sales to
unaffiliated customers.
(b) For the purpose of calculating the average production costs per Mcf
equivalent, barrels of oil were converted to Mcf using six Mcf of natural
gas to one barrel of oil. Production costs do not include depreciation or
depletion.
11
<PAGE> 12
WELLS AND DEVELOPED ACREAGE
The table below shows gross and net wells in which the Company has a
working interest at August 31, 1997, and includes wells in which the
Company has royalty or overriding royalty interests.
<TABLE>
<CAPTION>
----------------------------------
Oil Gas
----------------------------------
<S> <C> <C>
Gross wells 233 923
Net wells 78 234
----------------------------------
</TABLE>
Gross developed acres and net developed acres by well classification are
not available. Net developed acres for both oil and gas is 76,617 acres.
UNDEVELOPED ACREAGE
The gross and net undeveloped leasehold acreage at the end of the fiscal
year is as follows:
<TABLE>
<CAPTION>
------------------------------------
Gross Net
------------------------------------
<S> <C> <C>
Alabama 388 61
Louisiana 1,110 210
Oklahoma 57,801 13,279
Texas 6,757 762
------------------------------------
Total 66,056 14,312
------------------------------------
</TABLE>
Of the net onshore undeveloped acres, approximately five percent lies in
the Ardmore Basin area, 28 percent in the Anadarko Basin area in Oklahoma,
31 percent in the Oklahoma portion of the Arkoma Basin, and three percent
in the Texas Gulf Coast area.
NET EXPLORATORY AND DEVELOPMENT WELLS DRILLED
The net interest in total wells drilled, by well classification, is as
follows:
<TABLE>
<CAPTION>
------------------------------------------------
Exploratory Development
------------------------------------------------
1997
<S> <C> <C>
Productive 0.0 3.8
Dry 0.0 1.5
---------------------------
Total 0.0 5.3
===========================
1996
Productive 0.0 2.7
Dry 0.6 1.8
---------------------------
Total 0.6 4.5
===========================
1995
Productive 2.4 6.3
Dry 1.8 1.9
---------------------------
Total 4.2 8.2
================================================
</TABLE>
PRESENT DRILLING ACTIVITIES
On August 31, 1997, the Company was participating in the drilling of 25
wells. The Company's net interest in these wells amounts to 3 wells.
FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS
None.
12
<PAGE> 13
ITEM 3. LEGAL PROCEEDINGS
FENT. ET UX V. OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK INC. ET AL.,
No. CJ-88-10148, District Court, Oklahoma County ("Fent I case"). On October 6,
1988, the Plaintiffs filed a petition for reimbursement for the cost of
replacement of a yardline and for repairing the gap in piping caused by the
relocation of the meter to the property line and as a class action for
similarly situated customers. The Company moved to dismiss the action on the
grounds the District Court did not have subject matter jurisdiction and a
failure to state a cause of action for which relief could be granted. The
District Court granted the motion to dismiss and the Plaintiffs appealed the
decision. On August 14, 1991, the Court of Appeals reversed the trial court's
decision and remanded the case for further proceedings. The appellate court
held that the trial court had erred in ruling both that it was without
jurisdiction and that the Plaintiffs had failed to state a cause of action,
instead finding that under Commission Rule 6(a) the Company could be
responsible for maintenance of the gas line up to the outflow side of the
meter. As a result, the Company could have a duty to repair the gap caused by
the removal of the meter and to maintain and repair the yard line. The case was
remanded to the District Court, the Company filed a related proceeding with the
Oklahoma Corporation Commission seeking an interpretation of the applicable
Commission rules, and although the Plaintiffs filed a motion in District Court
to certify the class, further proceedings in the case were stayed pending
resolutions of the appeal of the decision in the related Corporation Commission
proceeding. The Corporation Commission proceeding was resolved. Plaintiffs
filed a motion to lift the stay which was granted by the Court, enabling the
case to proceed with discovery on the issue of whether claims should be
certified as a class action and Plaintiff's allowed to act as class
representatives. The Company filed a motion to strike on the basis of the
Oklahoma Corporation Commission decision in Fent III (see below) that the
Company was not responsible for non-Fent yardlines, which was granted on July
26, 1996. Fent appealed the decision of the District Court and on April 8,
1997, the appeal was assigned to Division 2 of the Court of Appeals. All briefs
have been filed.
APPLICATION OF OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK INC. FOR A
DETERMINATION THAT UNDER THE COMMISSION'S EXISTING NATURAL GAS UTILITY RULES AND
REGULATIONS AND OKLAHOMA NATURAL'S EXISTING SERVICE RULES AND REGULATIONS, THE
GAS UTILITY CUSTOMERS OF OKLAHOMA NATURAL GAS COMPANY, EXCEPT JERRY R. FENT AND
MARGARET B. FENT, ARE RESPONSIBLE FOR INSTALLING AND MAINTAINING ALL PIPING
BETWEEN THE CUSTOMERS' PROPERTY OR CURB LINES, AND SUCH CUSTOMERS' POINTS OF
CONSUMPTION OF GAS, Cause PUD No. 95000233, Oklahoma Corporation Commission
(Fent III Case). On February 24, 1992, in Cause PUD No. 001123 (hereinafter
referred to as the Fent II Case), the Commission issued Order No.363449, holding
that under the Commission Gas Rules and ONG Rules, a gas utility customer is
financially responsible for the installation, maintenance, repair or replacement
of the customer's yard line, being the line lying between the gas utility's main
located at the property or curb line, or easement, and the premises being
served, and lying outside of any easement, regardless of where the gas meter is
located. The Commission's Order in Fent II was subsequently appealed to the
Oklahoma Supreme Court, which issued an opinion in Fent v. Oklahoma Natural Gas
Co., 898 P.2nd 126 (1994), resulting in a reversal of the Commission's Order. In
its opinion the Supreme Court stated that its pronouncement did not question the
general power of the Commission to regulate utilities by rulemaking and to
interpret its own rules; it was addressed narrowly to the agency's attempt to
affect the Fent's pending district court claim. However, the Court reversed the
Commission's Order in its entirety. On September 27, 1995, the Company filed an
application requesting that the Commission reaffirm its order in Fent II as it
applies to ratepayers other than the Fents, for application in the Fent I case
if it should be certified as a class action. On November 29, 1995, Fent filed
for a Writ of Prohibition with the Oklahoma Supreme Court which was denied on
March 6, 1996. A hearing on the Company's application was held April 10, 1996
and an Order issued April 24, 1996 granting the Company's application. The Fents
and Harold Jenks (another customer of the Company) have appealed the Order to
the Oklahoma Supreme Court. The Company filed a response to the appeal and a
motion to dismiss the Fent's appeal for lack of standing and their appeal was
dismissed on September 23, 1996. The Jenks appeal is still pending. All briefs
have been filed and the appeal was assigned to Division 3 of the Court of Civil
Appeals on April 8, 1997.
13
<PAGE> 14
On November 17, 1997, the Court of Civil Appeals issued an Opinion which
reversed the Commission order. The court acknowledged that Fent I applies only
to the Fents' claim against ONG, and that Fent II did not decide any issue
relating to the financial responsibility on the Company or its other customers
as to installing, maintaining, repairing or replacing yardlines. However, the
court held that the Commission Order must fall "because it is an attempt to
pre-judge future disputes." The court stated that ONG was, in effect,
attempting to secure an order exempting it from liability on future unknown
claims. According to the court, while the Commission may interpret its own
rules and those of a public utility "when a dispute arises," it may not
determine whether ONG would have liability in any future case. The Company
anticipates filing a petition for certiorari, which would be due December 8,
1997.
IN THE MATTER OF COMMISSIONER BOB ANTHONY'S INSPECTION OF THE BOOKS AND RECORDS
OF ANY PUBLIC SERVICE CORPORATION AND EXAMINATION, UNDER OATH, ANY OFFICER,
AGENT, OR EMPLOYEE OF SUCH, IN RELATION TO THE BUSINESS AND AFFAIRS OF ARKANSAS
LOUISIANA GAS COMPANY, A DIVISION OF NORAM ENERGY CORP. AND OKLAHOMA NATURAL GAS
COMPANY, A DIVISION OF ONEOK INC. PURSUANT TO OKLAHOMA CONSTITUTION ARTICLE 9,
SECTIONS 18, 28 AND 34, Cause No. PUD 960000039 and related dockets (PUD 96-85,
96-100, 96-186) Oklahoma Corporation Commission. Commissioner Anthony filed
notice on February 13, 1996, and thereafter sought, in his capacity as an
individual Commissioner, to investigate transactions between the Company and
other entities in connection with the 1993 settlement of a long-running gas
contract dispute between the Company and one of its gas suppliers, Creek
Systems. The principal subject of the inquiry was a new gas supply arrangement
entered into in connection with the settlement between the Company and an entity
called Dynamic Energy Resources, which in turn assigned its interest in the
contract to two other unrelated companies. Commissioner Anthony contended that
he was questioning whether the new gas supply arrangement entered into as a
result of the settlement had resulted in excessive gas costs to the Company's
customers. The gas supply contracts in question had been examined in earlier
audits by the Commission staff and no improper costs or other improprieties had
been found. After extensive Commission proceedings and an original action in the
Oklahoma Supreme Court challenging Anthony's authority to conduct such an
individual investigation, a compromise was reached among all interested parties
(other than Commissioner Anthony) pursuant to which another Commission staff
investigation of the matter was conducted with full cooperation by the Company.
On December 17, 1996, the Commission Staff in a related Cause (Cause PUD No.
960000186) filed a report finding no improprieties and no excess charges on the
part of the Company. On July 1, 1997, Commissioner Anthony filed a document
entitled "Need for Disallowance on ONG Cost for Contracts with Dynamic Energy
Resources, Inc." claiming ratepayers will pay at least $40 annually more than
necessary under the Contracts and cost to customers should be decreased to
eliminate excess gas costs. On August 14, 1997, Commissioner Anthony filed a
document entitled "Need to Place the Company's Fuel Tariff Interim Subject to
Refund," which was a memorandum to Anthony from his Administrative Assistant,
James Proctor. The memorandum recommended that the Commission conduct a hearing
and find that ONG's fuel adjustments clause should be set interim, subject to
refund, pending a full public hearing on the merits of the Company's contracts
arising from the Dynamic transaction. The memorandum concluded that the Company
will pay up to an estimated $54.1 million more for gas under the contract than
under the Creek Systems contract. It suggested the contract was executed solely
to "eliminate adverse publicity and potentially damaging civil litigation in a
way which avoided a direct reduction in shareholders equity." However, no formal
Commission proceedings which will require a vote of the Commission have been
instituted in response to Commissioner Anthony's findings.
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.
14
<PAGE> 15
ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS
(A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS
The WRI acquisition was submitted and voted upon by shareholders September
25, 1997.
(B) EXECUTIVE OFFICERS OF THE REGISTRANT
All executive officers are elected at the annual meeting of directors and
serve for a period of one year or until their successors are duly elected.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
PERIOD SERVED BUSINESS EXPERIENCE
NAME AND POSITION AGE IN SUCH CAPACITY IN PAST FIVE YEARS
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
LARRY W. BRUMMETT 47 1994 to present Chairman of the Board of Directors,
Chairman of the Board, President, and Chief Executive Officer
President, and Chief
Executive Officer
1993 to 1994 Executive Vice President of ONEOK
1992 to 1993 Executive Vice President of Oklahoma
Natural Gas Company (ONG)
- ---------------------------------------------------------------------------------------------------------------
DAVID L. KYLE 45 1995 to present Member of the Board of Directors
President and Chief 1994 to present President and Chief Operating Officer
Operating Officer of of Oklahoma Natural Gas Company
Oklahoma Natural Gas 1992 to 1994 Executive Vice President of
Company Oklahoma Natural Gas Company
- ---------------------------------------------------------------------------------------------------------------
JERRY D. NEAL 58 1992 to present Vice President, Treasurer, and Chief
Vice President, Treasurer, and Financial Officer (Principal Financial
Chief Financial Officer, and Accounting Officer)
(Principal Financial and
Accounting Officer)
- ---------------------------------------------------------------------------------------------------------------
NORMAN E. DUCKWORTH 63 1996 to 1997 Vice President and Secretary
Vice President and Secretary 1992 to 1996 Vice President of Human Resources
- ---------------------------------------------------------------------------------------------------------------
EUGENE N. DUBAY 49 1996 to present Vice President of Corporate Development
Vice President of 1992 to 1995 Executive Vice President and
Corporate Development Chief Operating Officer of Missouri Gas
Energy
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
15
<PAGE> 16
PART II
ITEM 5. MARKET PRICE AND DIVIDENDS ON THE REGISTRANT'S COMMON STOCK AND
RELATED SHAREHOLDER MATTERS
(A) MARKET INFORMATION
The Company's common stock is listed on the New York Stock Exchange under
the trading symbol OKE. The corporate name ONEOK is used in newspaper stock
listings. The high and low market prices of the Company's common stock for
each fiscal quarter during the last two fiscal years were as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1997 HIGH LOW
- -------------------------------------------------------------------------------
<S> <C> <C>
First quarter $ 28 5/8 $ 24 7/8
Second quarter $ 30 7/8 $ 26
Third quarter $ 31 1/8 $ 25 7/8
Fourth quarter $ 35 5/16 $ 30
- -------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1996 HIGH LOW
- -------------------------------------------------------------------------------
<S> <C> <C>
First quarter $ 24 13/16 $ 22
Second quarter $ 23 7/8 $ 20
Third quarter $ 27 1/2 $ 21 1/8
Fourth quarter $ 28 7/8 $ 24 3/8
- -------------------------------------------------------------------------------
</TABLE>
(B) HOLDERS
There were 13,189 holders of the Company's common stock at August 31, 1997.
(C) DIVIDENDS
Quarterly dividends declared on the Company's common stock during the last
two fiscal years were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1997 1996
- -------------------------------------------------------------------------------
<S> <C> <C>
First quarter $ .30 $ .29
Second quarter $ .30 $ .29
Third quarter $ .30 $ .30
Fourth quarter $ .30 $ .30
------ ------
Total $ 1.20 $ 1.18
- -------------------------------------------------------------------------------
</TABLE>
Debt agreements pursuant to which the Company's outstanding long-term and
short-term debt has been issued limit dividends and other distributions on
the Company's common stock. Under the most restrictive of these provisions,
$27,412,000 of retained earnings is so restricted. On August 31, 1997,
$205,411,000 was available for dividends on the Company's common stock.
ITEM 6. SELECTED FINANCIAL DATA
Following are selected financial data for the Company for each of the last five
fiscal years. Dollar amounts are in millions of dollars, except per share
amounts.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $1,161.9 $1,224.3 $954.2 $784.1 $789.1
Operating income before interest
and income taxes $128.8 $121.0 $105.5 $92.0 $96.5
Net income $59.3 $52.8 $42.8 $36.2 $38.4
Total assets $1,237.4 $1,219.9 $1,181.2 $1,148.1 $1,115.1
Long-term debt $347.1 $351.9 $363.9 $376.9 $391.9
Earnings per common share $2.13 $1.93 $1.58 $1.34 $1.43
Dividends per common share $1.20 $1.18 $1.12 $1.11 $1.06
Percent of payout 56.2% 61.1% 70.9% 82.8% 74.1%
Common equity per share $16.47 $15.21 $14.38 $13.88 $13.63
Return on common equity 12.75% 12.64% 10.90% 9.65% 10.46%
Ratio of earnings to
fixed charges 3.71 3.44 2.56 2.39 2.33
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
16
<PAGE> 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OPERATING ENVIRONMENT AND OUTLOOK
Management believes that changes in the natural gas business are inevitable and
that such changes will significantly affect the manner in which natural gas and
related services are marketed. In response to this trend, commencing in 1994,
management conducted a strategic review of its business and of ongoing
developments in the natural gas distribution and energy related industry
regarding competition, regulation and consolidation. Management concluded that
the domestic natural gas business was undergoing a process of deregulation which
would lead, over the next several years, to "unbundling" of services at the
residential level. Management further concluded that markets for electricity and
natural gas were converging and consolidating and that these trends and
competition for customers would alter the structure and business practices of
companies serving these markets in the future.
In order to better position the Company competitively, management determined
that it should seek both to expand its gas distribution operations and become a
provider of energy services not limited to natural gas through acquisitions or
strategic alliances with companies that would enhance and expand its natural gas
distribution, marketing and transportation business.
The Company has taken steps this year to strengthen its competitive edge and
position it to be a leader in the industry. The most significant of these steps
being the strategic alliance with Western Resources, Inc. announced in December
1996 and effective November 26, 1997. The agreement with Western provides for
the Company to own and operate the natural gas assets of Western making the
Company the eighth-largest natural gas distributor in the country with about 1.4
million customers. Since closing of the transaction, Western will own
approximately three million shares of common stock and 19 million shares of
Series A convertible preferred stock making Western the largest shareholder of
the Company. The Series A convertible preferred stock will be non-voting and
convertible into common shares only under certain circumstances. Additionally, a
shareholder agreement containing standstill provisions prevents Western from
increasing their position in the Company and restricts the conditions under
which Western can vote any common shares created from conversion of its
preferred stock.
The transaction is a mutually beneficial business alliance between two
experienced energy companies, and provides the Company an excellent opportunity
for growth. Rather than reducing the Company's interests in acquisition
opportunities, it provides greater incentives and strengthens the Company's
financial position.
OTHER OPERATING HIGHLIGHTS INCLUDE:
o REGULATED OPERATIONS - The natural gas operations of Western represents a
strategic fit for the Company's regulated operations as the possibilities of
unbundling begin to unfold. Through the alliance, the Company will obtain
both the local gas distribution business and MCMC, an intrastate gas
transmission company, currently owned and operated by Western. MCMC is
authorized to provide no-notice gas transmission, wheeling, parking,
balancing and storage services to third parties based on prevailing market
prices.
Unbundling should enhance customer choices, service and value and potentially
decrease unit costs, increase throughput, allow broader use of the Company's
assets and strengthen economic development. The OCC continues to study
unbundling and while no rules have yet been proposed by the OCC, nor any laws
passed by the state legislature mandating restructuring of the gas industry,
it is an issue being addressed by both bodies.
Changes initiated by the Company in 1995 allowed rates to be restructured for
large industrial customers, positioning the Company to more effectively
compete for additional customers. Additionally, the OCC approved a request
for a temperature adjustment clause that normalizes the effect of weather
during the heating season, the first such program approved in Oklahoma.
17
<PAGE> 18
o NONREGULATED OPERATIONS - The Company continues to enhance the value of its
non-regulated operations through strategic acquisitions. As a result of the
Western alliance, the Company will acquire additional marketing and
processing businesses which will complement the activities of the existing
segments.
The acquisition of PSEC, Inc., an independent oil and gas producing company
added substantial hydrocarbon reserves. The February 1997, acquisition of
this independent oil and gas producing company, included 180 wells with
proven reserves of 20 Bcf of natural gas and 167,000 barrels of oil
concentrated in three counties in Oklahoma. A 42 percent interest in the
Sycamore Gas Gathering System was also part of the acquisition.
Beginning in 1996, the production operation has concentrated on exploitation
activities and reserve ownership in Oklahoma, and has reduced its exploration
activities. As a result, 93 percent, 89 percent and 53 percent of the
Company's reserves are located in Oklahoma in 1997, 1996, and 1995.
CONSOLIDATED OPERATIONS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ---------------------------------------------------------------------------------
<S> <C> <C>v <C>
FINANCIAL RESULTS
Operating revenues - regulated $598,390 $538,169 $594,923
Operating revenue - nonregulated 563,537 686,176 359,272
- ---------------------------------------------------------------------------------
Total operating revenue 1,161,927 1,224,345 954,195
Operating costs 958,626 1,030,442 795,202
Depreciation, depletion and
amortization 74,509 72,868 53,480
- ---------------------------------------------------------------------------------
Operating income $ 128,792 $ 121,035 $105,513
=================================================================================
</TABLE>
[EARNINGS PER SHARE GRAPHIC]
Graph shows e.p.s. of $2.13, $1.93 and $1.58 for fiscal 1997, 1996 and
1995 respectively.
RESULTS OF OPERATIONS - The performance of the nonregulated operations played a
major role in the Company's success in 1997. The strong performance of the
Company's production operation reflects the effect of additional gas reserves
acquired, operational changes and efficiencies, general market conditions and an
aggressive marketing campaign conducted through the Company's gas marketing
operation. Gas production volumes increased 5.2 Bcf over one year ago and the
average price increased $.30 over one year ago. The operating income for the gas
processing operation increased by 43 percent over one year ago and reflects
substantially higher product prices early in fiscal 1997.
The increase in operating income for the regulated operation is due to decreases
in operating expenses primarily due to reductions in labor and associated
employee welfare costs.
The strong performance of the Company's regulated business, the rapid growth of
the gas marketing segment and organizational changes implemented to maximize the
value of its nonregulated businesses contributed to the increase in net income
in 1996 over 1995. Higher earnings attributable to the regulated business are
the result of reduced costs and increased margins. Growth of the gas marketing
operations is attributable to weather related demand and a focus on daily
trading.
RISK MANAGEMENT - To minimize the risk from market fluctuations in the price of
natural gas and oil, the Company's nonregulated operations use commodity
derivative instruments such as future contracts, swaps and options
(collectively, derivatives) to hedge existing physical gas inventory, and
purchase or sale commitments. None of these derivatives are held for speculative
purposes and, in general, the Company's risk management policy requires that
positions taken with derivatives be offset by positions in physical transactions
or other derivatives. For each of the years in the three year period ended
August 31, 1997, derivatives were primarily used by ONEOK Gas Marketing as a
method of eliminating unacceptable risks with respect to changes in the price of
gas or the cost of the intervening transportation associated with certain
contracts.
18
<PAGE> 19
The Company's production segment utilizes derivatives in order to hedge
anticipated sales of oil and natural gas production. These anticipated
transactions have been hedged with commodity swaps agreements whereby the
Company is able to set the price to be received for the future production thus
eliminating the risk of declining market prices between the origination date of
the swap and the month of production. The Company's strategy in hedging
anticipated transactions is to eliminate the variability in earnings of its
production segment as a result of market fluctuations. To the extent that
management does not terminate a hedge or enter into an opposing derivative, the
current strategy will limit the potential gains which could result from
increases in market prices above the level set by the hedge.
The Company adheres to policies and procedures which limit its exposure to
market risk from open positions and monitors daily its exposure to market risk.
The results of the Company's derivative trading activities continue to meet its
stated objectives. For further discussion, see OTHER, Price Risk Management at
page 26 and Note H of "Notes to Consolidated Financial Statements".
ACCOUNTING POLICIES - The regulated operations of the Company are primarily
subject to accounting requirements of the OCC and the provisions of Statement of
Financial Accounting Standards No. 71 "Accounting for the Effects of Certain
Types of Regulation." Accordingly, the allocation of costs and revenues to
accounting periods for ratemaking and regulatory purposes may differ from bases
generally applied by nonregulated companies. Such allocations to meet regulatory
accounting requirements are considered to be generally accepted accounting
principles for regulated utilities provided that there is a demonstrable ability
to recover any deferred costs in future rates.
The Company views its segments as operating within either a rate regulated
environment (regulated operations) or a nonregulated (nonregulated operations).
The nonregulated environment is further viewed as having three primary,
vertically integrated segments: marketing, processing and production.
REGULATED OPERATIONS
Oklahoma Natural Gas Company, ONG Transmission Company, and ONG Sayre Storage
Company comprise a fully integrated intrastate natural gas distribution and
transmission business which purchases, stores, transports, and distributes
natural gas for sale to wholesale and retail customers primarily in the State of
Oklahoma, and leases pipeline capacity to customers for their use in
transporting natural gas to their facilities. ONG Transmission Company
transports gas for others under Section 311(a) of the Natural Gas Policy Act of
1978 (NGPA). They are currently consolidated for ratemaking purposes by the
Oklahoma Corporation Commission.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
FINANCIAL RESULTS
Gas Sales $543,662 $487,294 $502,427
Cost of gas 308,057 247,299 316,867
- ----------------------------------------------------------------------------------------
Gross margin on gas sales 235,605 239,995 185,560
Pipeline capacity lease margins 41,974 41,684 86,697
Other revenues 13,890 11,394 7,551
- ----------------------------------------------------------------------------------------
Net revenues 291,469 293,073 279,808
Operating expenses 139,662 144,927 146,986
Depreciation depletion and
amortization 51,375 50,805 41,252
- ----------------------------------------------------------------------------------------
Operating Income $100,432 $ 97,341 $ 91,570
========================================================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
1997 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
VOLUMES (MMcf)
Gas sales
Residential 57,006 58,681 52,804
Commercial 28,860 29,918 25,288
Industrial 11,384 15,145 39,095
Pipeline capacity lease 173,134 158,527 134,130
- ----------------------------------------------------------------------------------------
Total 270,384 262,271 251,317
========================================================================================
</TABLE>
19
<PAGE> 20
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
GROSS MARGIN PER Mcf
Residential $ 3.00 $ 2.91 $ 2.55
Commercial $ 2.23 $ 2.16 $ 1.95
Industrial $ 0.95 $ 0.85 $ 0.73
Pipeline capacity leases $ 0.19 $ 0.20 $ 0.46
===============================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Number of customers 733,621 729,467 724,201
Customers per employee 426 404 377
Capital expenditures
(thousands) $ 67,747 $ 42,900 $ 55,800
Identifiable assets
(millions) $ 1,026 $ 1,019 $ 1,023
- -------------------------------------------------------------------------------
</TABLE>
OPERATIONAL HIGHLIGHTS - The Company dominates the core energy service markets
with over a 90 percent market share for water heating, cooking and home heating.
Annual cost comparisons with electricity for these same services indicate that
gas costs were at least 50 percent less, the largest difference being in home
heating at 70 percent less. On a gas to gas comparison, Oklahoma Natural Gas
Company rates were lower than the regional and national averages for
residential, firm industrial and interruptible industrial services.
Highlights of significant operating changes over the past three years include:
o Signed contract to transport gas to four natural gas-fired electric
generating plants owned by Public Service Company of Oklahoma under PCL
agreements. Construction on facilities to serve two of the plants was
completed during the year and construction will be completed on the
facilities to serve the last two plants early in fiscal 1998.
o Strengthened cost controls throughout the organization. Total employees
dropped by approximately 4.6 percent. This was accomplished through attrition
and without compromising customer safety. Operating expense per customer
decreased 4.6 percent.
o Began work on a two and one-half year project to significantly improve the
availability of gas storage. The first phase of the project is intended to
double the injection capacity of the storage. The second phase, combined with
previous horizontal drilling, will double the withdrawal capacity of the
storages. These improvements are being accomplished at a fraction of the cost
to develop new storages.
o Changes initiated by Oklahoma Natural Gas in 1995 allowed rates to be
restructured for large industrial customers, positioning the Company to more
effectively compete for additional customers. In addition, the OCC approved a
request for a temperature adjustment clause that normalizes the effect of
weather during the heating season, the first such program approved in
Oklahoma.
REGULATORY INITIATIVES - The OCC's Notice of Inquiry on restructuring Oklahoma's
gas utility industry has set into motion the process of unbundling products and
services. The Company supports the unbundling of at least the transmission,
gathering, storage, customer service and gas supply functions and is working
closely with the OCC to develop proposed rules. However, because of the
inefficient and costly duplication of certain functions, such as local
distribution service, regulation will continue to be necessary in certain areas.
Customer choice is the driving force behind the restructuring efforts and will
ultimately provide a wide array of services from which to choose. The Company
has already unbundled the gas supply function for many industrial and large
commercial customers through the PCL program and envisions unbundling will
eventually allow all customers to choose their gas suppliers and other services
as well.
CAPITAL EXPENDITURES - The Company's capital expenditure program includes
expenditures for extending service to new areas, increasing system capabilities
and general replacements and betterments. The 1997 capital expenditure program
included $49 million for new business development including service to PSO's
four power plants and $7 million to improve peak storage deliverability. It is
the Company's practice to maintain and periodically upgrade facilities to assure
20
<PAGE> 21
safe, reliable and efficient operations. The 1996 capital expenditure program
included $10 million for new business development and $2 million to improve peak
storage deliverability.
OPERATING RESULTS - Lower gross margins on gas sales in the current year result
primarily from lower usage by customers whose gas sales and degree days are not
normalized, increased cost of gas used in operations, and unrecovered gas costs.
Actual degree days in 1997 were 3,566 as compared to 3,617 in 1996. Degree days
is an industry measure of temperature variations from an established normal
temperature of 65 degrees; a higher number of degree days reflects colder
weather on the average. Rates are designed to recover the cost of gas consumed
in operations through margins billed to customers rather than through
application of the Unrecovered Purchased Gas Cost adjustment used to recover the
actual cost of gas delivered to customers. Therefore, operating gas costs may
not be fully recovered under this methodology when sales volumes are less than
that at which rates were established or gas cost per Mcf is higher than that at
which rates were established. Both of these factors occurred in 1997 resulting
in the increased cost of gas. Fluctuations in the cost of gas between years
reflects volume and spot market fluctuations. Changes in its gas purchasing and
pricing practices approved in the June 1995 rate order resulted in a larger
portion of its gas supply being purchased at spot market prices. The significant
decrease in PCL rates in 1996 reflects the rate restructuring completed in 1995
which lowered rates to our large industrial customers in order to compete more
effectively.
Operating expenses decreased in 1997 as compared to 1996 and to 1995 primarily
due to reductions in labor and associated employee welfare costs.
NONREGULATED OPERATIONS
The Company's nonregulated operations are involved in the production, processing
and marketing of natural gas, oil and natural gas liquids. The Company's
producing properties are concentrated principally in Oklahoma where it also owns
nonoperated interests in 15 gas liquids extraction plants in 11 plant locations.
The gas marketing subsidiary directs its activities to end users in the
mid-continent region of the United States. The Company also operates its
headquarters office building and a parking garage.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
FINANCIAL RESULTS
Gas sales $484,674 $612,595 $328,890
Cost of gas 470,878 596,491 320,572
- --------------------------------------------------------------------------------
Gross margins on gas sales 13,796 16,104 8,318
Gas and oil production 38,159 25,181 20,799
Gas processing 25,326 20,901 18,461
Other 9,534 16,560 11,800
- --------------------------------------------------------------------------------
Net revenues 86,815 78,746 59,378
Operating costs 35,321 32,989 33,207
Depreciation, depletion
and amortization 23,134 22,063 12,228
- --------------------------------------------------------------------------------
Operating income $ 28,360 $ 23,694 $ 13,943
================================================================================
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING INFORMATION
Natural gas volume (MMcf) 205,204 309,965 221,561
Marketing 14,565 9,406 8,775
Natural gas production 6,109 6,883 7,560
- --------------------------------------------------------------------------------
225,878 326,254 237,896
- --------------------------------------------------------------------------------
Less intersegment sales
Marketing 9,384 7,822 41,262
Natural gas production 6,652 3,978 1,640
Residue gas 6,109 6,880 5,095
- --------------------------------------------------------------------------------
22,145 18,680 47,997
- --------------------------------------------------------------------------------
Net natural gas volumes 203,733 307,574 189,899
================================================================================
</TABLE>
MARKETING
OPERATIONAL HIGHLIGHTS - The Company's marketing operation purchases and markets
natural gas, primarily in the mid-continent area of the United States. Beginning
in fiscal 1996, the Company started implementation of a new strategy to focus on
daily trading rather than on low margin baseload trading. The transition to
daily trading was achieved through the increased use of gas storage facilities,
hedging and transportation arbitraging. In fiscal 1997, having successfully
developed a strong base of daily trading customers, the Company began reducing
the level of non-strategic baseload trading it performed. Accordingly, total
volumes sold are lower in 1997 than the prior year, however, the gross
21
<PAGE> 22
margins earned per Mcf are higher than in prior years as a result of this change
in trading mix. The average gross margin per Mcf, for all trading, increased by
31 percent in 1997 and 38 percent in 1996 over the prior year.
The Company was the successful bidder to supply gas to several natural gas-fired
electric generating power plants owned by Public Service Company of Oklahoma.
Gas will be supplied under both firm and interruptible gas sales agreements and
transported by the regulated operation.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
MARKETING SEGMENT
Natural gas sales $484,674 $612,595 $328,890
Cost of gas 470,878 596,491 320,572
- -------------------------------------------------------------------------------
Gross margin on gas sales 13,796 16,104 8,318
Operating cost, net 5,455 2,697 3,458
Depreciation, depletion,
and amortization 482 484 80
- -------------------------------------------------------------------------------
Operating income $ 7,859 $ 12,923 $ 4,780
===============================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1997 1996 1997
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING INFORMATION
Natural gas volumes (MMcf) 205,204 309,965 221,561
Capital expenditures
(thousands) $ 373 $ 370 $ 921
Identifiable assets
(thousands) $ 63,828 $ 71,200 $ 41,400
- -------------------------------------------------------------------------------
</TABLE>
PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising from
fluctuations in both the market price and transportation costs of natural gas,
the Company routinely enters into natural gas futures contracts, swaps and
options as a method of protecting its margins on the underlying physical
transactions. However, net open positions in terms of price, volume and
specified delivery point do occur. For further discussion, see OTHER, Price Risk
Management at page 26.
OPERATING RESULTS - The Company's continued focus on daily trading and away from
baseload trading has had a significant impact on the operating results of the
marketing operation. Overall gross margins per Mcf increased in 1997 over the
prior year despite a decrease in both volumes sold and total gross margins. The
decrease in volumes is indicative of management's decision to forgo baseload
business in order to further develop its daily trading practice. Total gross
margins was negatively impacted by this and a lower degree of price dispersion
in the daily market. The Company will continue to pursue an aggressive marketing
strategy using hedging and gas storage to further develop its daily trading
market. The increase in operating costs in 1997 is attributable to a
non-recurring charge. The increase in volumes and total gross margins in 1996
over the prior year resulted from the shift to daily trading while maintaining
the base load trading business. Margins in the daily trading market were
favorably affected by weather related demand. In January 1995, the Company
acquired the remaining 50 percent interest in a gas marketing entity. The
results of operations attributable to that investment prior to that date are
included in operating costs.
PROCESSING
OPERATIONAL HIGHLIGHTS - The Company's processing operation has nonoperating
interests in 15 gas processing plants at 11 plant locations whose operations
include the extraction and separation of natural gas liquids (NGLs) into
distinct products (e.g., ethane/propane mix, propane, iso and normal butane, and
natural gasoline). Factors contributing to the volatility in earnings are
fluctuations in the price of natural gas which is consumed as "fuel and
shrinkage" in the extraction process, fluctuation in the discreet market prices
of NGLs, competition or processing plant capacity utilization.
Successful pursuit of producer alliances has provided for total dedication of
production by several producers to be processed in several joint-owned plants.
In January 1997, the Company acquired an 8 percent interest in the Indian Basin
Gas Plant operated by Marathon Oil Company in Eddy County, New Mexico. Through
the strategic alliance with Western Resources, the Company's interest will
increase to 42 percent when the alliance is approved and the transaction closed.
22
<PAGE> 23
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS 1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
PROCESSING SEGMENT
Natural gas liquids
and residue sales $23,107 $18,423 $15,970
Other (65) 261 148
- ----------------------------------------------------------------------------------
Operating revenues 23,042 18,684 16,118
Operating costs (net) 7,770 7,641 7,999
Depreciation, depletion,
and amortizations 2,393 2,063 1,790
- ----------------------------------------------------------------------------------
Operating income $12,879 $ 8,980 $ 6,329
==================================================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING INFORMATION
Residue gas (MMcf) 6,109 6,883 7,560
Natural gas liquids sold
(MGallons) 200,143 195,979 205,464
Average NGL's price
(Gallons) $0.365 $0.297 $0.261
Fuel and shrink price
(MMbtu) $2.07 $1.82 $1.64
Capital expenditures
(thousands) $10,563 $5,183 $1,226
Identifiable assets
(thousands) $36,049 $26,700 $25,200
- ----------------------------------------------------------------------------------
</TABLE>
CAPITAL EXPENDITURES - The Company spent $9 million during 1997 for its share of
the Indian Basin Plant, for expansion of plant, and for improvements to increase
product recovery. The remaining $1.7 million in capital expenditures relates to
capital required to sustain operations. Prior years' expenditures generally
related to capital required to sustain operations.
OPERATING RESULTS - Volumes of natural gas liquids sold increased and higher
product prices resulted in an increase in natural gas liquids revenues for 1997.
Volumes declined in 1996 due to some periods of ethane rejection but natural gas
liquids were strengthened by increased prices. An increase in fuel and shrink
partially offset increases in product prices and volumes sold.
PRODUCTION
OPERATIONAL HIGHLIGHTS - The Company's strategy is to concentrate ownership of
hydrocarbon reserves in its service territory in order to add value not only to
its existing production operations but also to the related processing,
marketing, transmission, and storage businesses. Accordingly, the Company
focuses on exploitation activities rather than exploratory drilling. As a result
of recent acquisitions, the number of wells the Company operates has increased.
In its role as operator, the Company controls operating decisions which impact
production volumes and lifting costs.
RISK MANAGEMENT - The volatility of energy prices has a significant impact on
the profitability of this segment. In an effort to manage price risk as much as
possible, the production segment expanded its hedging program in late 1996. As
of August 31, 1997, approximately 25 percent of anticipated gas production in
1998 has been hedged primarily with swap agreements. See Risk Management, Page
18.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS 1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
PRODUCTION SEGMENT
Natural gas sales $31,496 $17,466 $13,236
Oil sales 6,663 7,716 7,563
Liquids and residue gas 2,219 2,477 2,491
Other 699 5,675 1,582
- ----------------------------------------------------------------------------------
Operating revenues 41,077 33,334 24,872
Operating costs 12,468 11,341 11,257
Depreciation, depletion,
and amortization 19,899 19,161 10,038
- ----------------------------------------------------------------------------------
Operating income $ 8,710 $ 2,832 $ 3,577
==================================================================================
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
OPERATING INFORMATION 1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved Reserves
Gas (MMcf) 83,293 74,068 39,226
Oil (MBbls) 2,014 2,010 3,247
- ----------------------------------------------------------------------------------
Production
Gas (MMcf) 14,565 9,406 8,775
Oil (MBbls) 336 435 466
- ----------------------------------------------------------------------------------
Average Price
Gas (Mcf) $2.16 $1.86 $1.51
Oil (BBls) $19.84 $17.73 $16.22
- ----------------------------------------------------------------------------------
Capital Expenditures
(thousands) $32,911 $46,733 $25,000
Identifiable Assets
(thousands) $100,062 $73,200 $60,000
- ----------------------------------------------------------------------------------
</TABLE>
23
<PAGE> 24
CAPITAL EXPENDITURES - During 1997, the Company purchased PSEC, Inc., an
independent oil and gas company in Oklahoma. The transaction included 180 wells
with proven reserves of 20 Bcf of natural gas and 167,000 barrels of oil.
Included in the transaction was PSPC, Ltd., which operates and holds a 42
percent interest in the Sycamore Gas Gathering System. The purchase was financed
with $9.3 million long-term debt and 334,252 shares of ONEOK common stock.
During 1996, the Company purchased substantially all of the Oklahoma oil and
natural gas properties of SCANA Petroleum Resources, Inc. The $43.1 million
purchase included over 500 producing properties of which 90 percent are
natural gas. Also in 1996, the Company sold all of its oil and gas properties in
Alabama and Mississippi for approximately $18.9 million. The Company acquired
working interests in oil and gas reserves located in Louisiana for approximately
$18.3 million in 1995.
Capital expenditures primarily related to a limited developmental drilling
program were approximately $6.7 million, $3.4 million and $5.9 million in 1997,
1996 and 1995, respectively.
OPERATING RESULTS - The increase in gas production volumes over the same period
one year ago is attributable to the effects of gas reserves acquired in the
latter part of fiscal 1996 and operational changes and efficiencies. The
increase in the average price of gas and oil is attributable to general market
conditions and an aggressive marketing campaign conducted through the Company's
gas marketing segment. Other revenues in 1996 reflect the gain on sale of
producing properties in Alabama and Mississippi. Operating efficiencies also
resulted in a decline of the operating cost per equivalent Mcf of sales. Total
depreciation, depletion and amortization before impairment losses increased, in
fiscal 1997 as a result of increased production. The Company recognized an $8.6
million impairment loss in fiscal 1996 upon the adoption of Statement of
Financial Accounting Standard No. 121, accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW ANALYSIS
Cash provided by operating activities continues as the primary source for
meeting cash requirements. However, due to seasonal fluctuations and additional
capital requirements, the Company accesses funds through short-term credit
agreements and, if necessary, through long-term borrowings. The Company believes
that internally generated funds and existing credit agreements will be
sufficient to meet its debt service, dividend payment and capital expenditure
requirements. However, certain events, such as significant acquisitions, may
require additional long-term debt or equity financing. The following discussion
of cash flows should be read in conjunction with the Company's "Consolidated
Statement of Cash Flows" and the supplemental cash flow information included in
Note O of "Notes to Consolidated Financial Statements".
OPERATING CASH FLOW
<TABLE>
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
FOR THE YEARS ENDED AUGUST 31, 1997 1996 1995
THOUSANDS OF DOLLARS
- -------------------------------------------------------------------------------
Cash provided by operating
activities 152,051 $105,050 $109,559
- -------------------------------------------------------------------------------
</TABLE>
Operating cash flows increased in 1997 over the prior year as a result of higher
earnings and lower net invested working capital. The decrease in net invested
working capital is primarily attributable to lower levels of gas in storage and
recovery of purchased gas costs. In accordance with an OCC order received in
late 1996, the Company recovered the remaining recoverable purchased gas costs
which
24
<PAGE> 25
accumulated during the 1996 heating season. The order granted recovery over a
twelve month period and provided for periodic changes in the base cost of gas in
order to reduce the impact on cash flow from future changes in the weighted
average cost of gas. Operating cash flow was slightly lower in 1996 as compared
to 1995 despite a $43 million increase in income before deferred tax and
depreciation, depletion and amortization expense which reflected an overall
increase in net income, changes in the components of current and deferred taxes
and the recovery through rates of deferred costs authorized in the 1995 rate
proceedings. This increase was offset by increases in net invested working
capital primarily related to gas in storage and the accumulation of recoverable
gas costs discussed above.
INVESTING CASH FLOW
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash used in investing activities $88,832 $71,985 $63,299
- --------------------------------------------------------------------------------
</TABLE>
CAPITAL EXPENDITURES - Total capital expenditures increased in both 1997 and
1996. As discussed in the "Results from Operations," the increase is
attributable to the acquisition of production and processing assets for
approximately $34 million and $43 million in each of those years respectively.
Acquisition of production assets in 1995 was $18 million. Capital expenditures
for 1998, excluding potential acquisitions, are estimated to be $143 million.
[CAPITAL EXPENDITURES AND ACQUISITIONS GRAPH]
Graph shows capital expenditures and acquisitions. Amounts for capital
expenditures are $77.7 million, $52.3 million and $65.0 million for fiscal 1997,
1996 and 1995 respectively. Capital acquisitions are $34.3 million, $43.1
million and $18.0 million for 1997, 1996 and 1995 respectively.
ASSET SALES - Approximately $18 million of proceeds was received in 1996
resulting from the sale of production assets. The sale of a pipeline investment
generated approximately $10.2 million in proceeds in 1995.
FINANCING CASH FLOW
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash used in financing activities $49,440 $44,966 $38,306
- --------------------------------------------------------------------------------
</TABLE>
SHORT-TERM DEBT - The Company uses short-term debt to help meet its need for
operating funds, which fluctuates with seasonal demands for gas purchases, the
levels of gas in storage and the Unrecovered Purchased Gas Cost (UPGC). A
short-term unsecured credit agreement with several banks provides aggregate
borrowings of up to $175 million for general corporate purposes. The Company
also has additional credit facilities available through a master note with Bank
of America and a short-term agreement with NationsBank which provide an
additional $30 million and $25 million in borrowing capability, respectively. No
borrowings were outstanding under these latter two agreements at August 31,
1997. The maximum amount of short-term debt authorized by the Board of Directors
is $175 million. Fluctuation in the amount of cash used in financing activities
in each of the years presented is primarily a factor of short-term borrowings.
LONG-TERM DEBT - As of August 31, 1997, the Company could have issued
approximately $311 million of additional long-term debt under the most
restrictive provisions contained in its various borrowing agreements. At August
31,1997, the equity component was 54 percent as compared to 51 percent a year
ago. Debt ratings are A3 by Moody's Investor Service and A- by Standard and
Poor's Corporation. The 8.7 percent series is currently callable and the 9.7
percent and 9.75 percent series have call options commencing in October 1996,
and December 1999 and 2000, respectively. Long-term debt in the amount of $9.3
million was issued in 1997 as partial payment for PSEC, Inc. and affiliates.
25
<PAGE> 26
STOCK AND DIVIDENDS - The Company had approximately 28 million shares of common
stock outstanding at August 31, 1997. Common stock dividends were $1.20, $1.18
and $1.12 per share in 1997, 1996 and 1995, respectively. Preferred stock
dividends were $1.78 in 1997 and $2.38 in each of the two prior years. The
preferred stock was redeemed by the Company in May 1997. Through the Company's
Stock Purchase and Dividend Reinvestment Program $5.5 million of dividends were
reinvested into common stock during 1997.
LIQUIDITY - The regulated businesses continue to face competitive pressure to
serve the substantial market represented by its large industrial customers. The
loss of a substantial portion of its industrial load, without recoupment of the
revenues from that loss, would have a materially adverse effect on the Company's
financial condition. The Company has successfully competed for such load in
large part with such innovative methods as its PCL and SISP programs. These
programs were all designed to provide competitive alternatives for Oklahoma
industry. Rate restructuring achieved in the June 1995 rate order further
reduces the Company's risk in serving its large industrial customers.
OTHER
PRICE RISK MANAGEMENT - Commodity futures contract options and swaps are
periodically used in the production, gas processing, and marketing operations to
hedge the impact of natural gas price fluctuations. Natural gas futures require
the Company to buy or sell natural gas at a fixed price. Under swap agreements,
the Company receives or makes payments based on the differential between a
specified price and the actual price of natural gas. Swaps and options allow the
Company to commit to purchase gas at one location and sell it at another
location without assuming unacceptable risk with respect to changes in price or
the cost of the intervening transportation. Natural gas options held to hedge
price risk provide the right, but not the requirement, to buy or sell natural
gas at a fixed price. The Company utilizes options to manage margins and to
limit overall price risk exposure. The Company's production operation
periodically uses commodity futures contracts and swaps to hedge the impact of
oil and natural gas price fluctuations. The Company's gas processing operation
uses futures to hedge the price of gas used in the natural gas liquid extraction
process. The gas marketing operation uses futures, options and swaps to lock in
margins on preexisting purchase or sale commitments for physical quantities of
natural gas. The Company adheres to policies and procedures which limit its
exposure to market risk from open positions and monitors daily its exposure to
market risk. Gains and losses on commodity futures contracts and swaps are
recognized in income when the underlying physical transactions are closed. At
August 31, 1997, the net deferred gain on these contracts was approximately $1.8
million.
NEW ACCOUNTING PRONOUNCEMENTS - In February 1997, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 128,
"Earnings per Share" ("SFAS 128"), which is required to be implemented for
fiscal years ending after December 15, 1997 and earlier application is not
permitted. SFAS 128 replaces the current "primary earnings per share"("primary
EPS") and "fully diluted earnings per share" ("fully diluted EPS") with "basic
earnings per share" ("basic EPS") and "diluted earnings per share" ("diluted
EPS"). Unlike the calculation of primary EPS which includes, in its denominator,
the sum of (1) actual weighted shares outstanding and (2) "common stock
equivalents" as that term is defined in the authoritative literature, basic EPS
is calculated using only the actual weighted average shares outstanding during
the relevant periods.
In June 1997, the FASB issued Statement of Financial Accounting Standards No.
130, Reporting Comprehensive Income (SFAS 130). SFAS 130 establishes standards
for reporting and display of comprehensive income and its components in a full
set of general purpose financial statements. It does not, however, specify when
to recognize or how to measure items that make up comprehensive income. SFAS 130
was issued to address the concerns over the practice of reporting elements of
comprehensive income directly in equity. SFAS 130 is effective for interim and
annual periods beginning after December 15, 1997.
The FASB also issued Statement of Financial Accounting Standards No. 131,
Disclosures about Segments of an Enterprise and Related Information (SFAS 131)
in June 1997. SFAS 131 supersedes FASB Statement No. 14, Financial Reporting
for Segments of a Business Enterprise, but retains the requirement to report
information about major customers. SFAS 131 replaces the "industry segment"
26
<PAGE> 27
concept of Statement 14 with a "management approach" concept as the basis for
identifying reportable segments. The management approach is based on the way
that management organizes the segments within the enterprise for making
operating decisions and assessing performance. Consequently, the segments are
evident from the structure of the enterprise's internal organization. It focuses
on financial information that an enterprise's decision makers use to make
decisions about the enterprise's operating matters. SFAS 131 is effective for
financial statements for periods beginning after December 15, 1997 and is not
anticipated to have a significant impact on the Company's segment reporting.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA MANAGEMENT'S
RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ONEOK Inc. is responsible for all information included in the
Annual Report, whether audited or unaudited. The financial statements have been
prepared in accordance with generally accepted accounting principles, applied in
a consistent manner, and necessarily include some amounts that are based on the
best estimates and judgments of management.
Management maintains a system of internal accounting policies, procedures, and
controls designed to provide reasonable assurance that assets are safeguarded
against loss or unauthorized use and that the financial records are reliable for
preparing financial statements. ONEOK Inc. maintains an internal auditing staff
responsible for evaluating the adequacy and application of financial and
operating controls and for testing compliance with management's policies and
procedures.
The accompanying consolidated financial statements of ONEOK Inc. and
subsidiaries as of August 31, 1997 and 1996, and for each of the years in the
three-year period ended August 31, 1997, have been audited by KPMG Peat Marwick
LLP, independent certified public accountants. Their audits include reviews of
the system of internal controls to the extent considered necessary to determine
the audit procedures required to support their opinion on the consolidated
financial statements. The Independent Auditors' Report appears herein.
The Board of Directors performs its oversight role for reviewing the accounting
and auditing procedures and financial reporting of ONEOK Inc. through its Audit
Committee. Both KPMG Peat Marwick LLP and our internal auditors have free access
to the Committee, without the presence of management, to discuss accounting,
auditing, and financial reporting matters.
27
<PAGE> 28
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders
ONEOK Inc.:
We have audited the accompanying consolidated balance sheets of ONEOK Inc. and
subsidiaries as of August 31, 1997 and 1996, and the related consolidated
statements of income, shareholders' equity, and cash flows for each of the years
in the three-year period ended August 31, 1997. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of ONEOK Inc. and
subsidiaries as of August 31, 1997 and 1996, and the results of their operations
and their cash flows for each of the years in the three-year period ended August
31, 1997, in conformity with generally accepted accounting principles.
As discussed in Note A to the consolidated financial statements, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets To
Be Disposed Of in fiscal year 1996.
KPMG Peat Marwick LLP
Tulsa, Oklahoma
September 24, 1997
28
<PAGE> 29
ONEOK Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Years Ended August 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Regulated $ 598,390 $ 538,169 $ 594,923
Nonregulated:
Marketing 459,574 598,300 266,426
Processing 71,617 58,395 64,874
Production 27,185 25,479 24,042
Other 5,161 4,002 3,930
----------- ----------- ---------
Total Nonregulated 563,537 686,176 359,272
----------- ----------- ---------
Total Operating Revenues 1,161,927 1,224,345 954,195
----------- ----------- ---------
Operating Expenses
Cost of gas 725,960 807,694 574,513
Operations and maintenance 210,175 201,259 200,443
Depreciation, depletion, and amortization 74,509 72,868 53,480
General taxes 22,491 21,489 20,246
Income taxes 34,839 33,037 25,342
----------- ----------- ---------
Total Operating Expenses 1,067,974 1,136,347 874,024
----------- ----------- ---------
Operating Income 93,953 87,998 80,171
----------- ----------- ---------
Interest
Interest on long-term debt 31,354 31,748 32,401
Other interest 3,376 3,184 4,878
Amortization of debt expense 518 530 512
Allowance for funds used during construction (563) (300) (424)
----------- ----------- ---------
Net Interest 34,685 35,162 37,367
----------- ----------- ---------
Net Income 59,268 52,836 42,804
Preferred Stock Dividends 285 428 428
----------- ----------- ---------
Income Available for Common Stock $ 58,983 $ 52,408 $ 42,376
=========== =========== =========
Earnings Per Share of Common Stock $ 2.13 $ 1.93 $ 1.58
=========== =========== =========
Average Shares of Common Stock
Outstanding (Thousands) 27,644 27,136 26,862
=========== =========== =========
</TABLE>
See accompanying notes to consolidated financial statements.
29
<PAGE> 30
ONEOK Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
August 31, 1997 1996
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Assets
Property
Distribution system $ 845,170 $ 802,910
Transmission system 310,231 258,870
Gas storage 4,195 4,195
Gas gathering -- 34,196
Oil and gas production 166,337 143,996
Gas processing 86,075 75,512
Other 17,485 16,973
---------- ----------
Total Property 1,429,493 1,336,652
Accumulated depreciation, depletion, and amortization 586,156 541,618
---------- ----------
Net Property 843,337 795,034
---------- ----------
Current Assets
Cash and cash equivalents 14,377 598
Accounts and notes receivable 100,937 119,338
Materials and supplies 4,303 5,136
Gas in storage 74,027 86,420
Advance payments for gas 3,700 5,764
Purchased gas cost adjustment 1,138 11,677
Other current assets 8,795 4,213
---------- ----------
Total Current Assets 207,277 233,146
---------- ----------
Deferred Charges and Other Assets
Investments 324 2,279
Regulatory assets, net 144,712 155,253
Other 41,757 34,179
---------- ----------
Total Deferred Charges and Other Assets 186,793 191,711
---------- ----------
Total Assets $1,237,407 $1,219,891
========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE> 31
ONEOK Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
August 31, 1997 1996
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Liabilities and Shareholders' Equity
Common Shareholders' Equity
Common Stock without par value: authorized 60,000,000
shares; issued and outstanding 28,079,783 and 27,260,646
shares in 1997 and 1996 $ 229,803 $ 207,084
Retained earnings 232,823 207,611
---------- ----------
Total Common Shareholders' Equity 462,626 414,695
Preferred stock: $50 par and involuntary liquidation value;
$53 voluntary liquidation value; Series A and B, 4 3/4%
(cumulative); authorized 340,000 shares; issued 180,000
shares of Series A in 1996 -- 9,000
---------- ----------
Total Shareholders' Equity 462,626 423,695
---------- ----------
Long-Term Debt 328,214 336,821
Current Liabilities
Long-term debt 18,909 15,050
Notes payable 45,000 50,223
Accounts payable 80,155 96,872
Accrued taxes 12,996 10,820
Accrued interest 7,376 7,732
Customers' deposits 6,218 6,316
Deferred income taxes 694 3,427
Other 17,699 12,190
---------- ----------
Total Current Liabilities 189,047 202,630
---------- ----------
Deferred Credits and Other Liabilities
Deferred income taxes 183,991 180,620
Customers' advances for construction
and other deferred credits 73,529 76,125
---------- ----------
Total Deferred Credits and Other Liabilities 257,520 256,745
---------- ----------
Commitments and Contingencies -- --
---------- ----------
Total Liabilities and Shareholders' Equity $1,237,407 $1,219,891
========== ==========
</TABLE>
31
<PAGE> 32
ONEOK Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
Years Ended August 31, 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Net Income $ 59,268 $ 52,836 $ 42,804
Depreciation, depletion, and amortization 74,509 72,868 53,480
Net losses of equity investees 257 173 811
Deferred income taxes (2,988) (2,038) (15,270)
Other -- (5,675) 613
Changes in assets and liabilities:
(Increase) decrease in accounts and notes receivable 18,401 (37,570) (32,726)
(Increase) decrease in inventories 13,226 (9,433) 12,331
(Increase) decrease in other assets (10,096) 8,027 5,816
(Increase) decrease in regulatory assets 384 1,431 (2,981)
Increase (decrease) in accounts payable and
accrued liabilities (14,897) 33,532 22,400
Changes in purchased gas cost adjustment 10,539 (14,383) 14,515
Increase (decrease) in deferred credits
and other liabilities 3,448 5,282 7,766
--------- --------- ---------
Cash provided by operating activities 152,051 105,050 109,559
--------- --------- ---------
Investing Activities
(Increase) decrease in other investments 1,698 -- 5,226
Proceeds from sale of investment -- -- 10,901
Capital expenditures, net (90,530) (89,582) (80,982)
Proceeds from sale of property -- 17,597 1,556
--------- --------- ---------
Cash used in investing activities (88,832) (71,985) (63,299)
--------- --------- ---------
Financing Activities
Payments of long-term debt (14,000) (12,000) (12,971)
Net issuance (payments) of notes payable (5,230) (5,052) 5,170
Dividends paid (28,033) (27,914) (30,505)
Issuance of common stock 7,363 -- --
Redemption of preferred stock (9,540) -- --
--------- --------- ---------
Cash used in financing activities (49,440) (44,966) (38,306)
--------- --------- ---------
Change in Cash and Cash Equivalents 13,779 (11,901) 7,954
Cash and Cash Equivalents at the
Beginning of Year 598 12,499 4,545
--------- --------- ---------
Cash and Cash Equivalents at
End of Year $ 14,377 $ 598 $ 12,499
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE> 33
ONEOK Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Shareholders' Equity
-------------------------------------------
Common Retained Preferred
Stock Earnings Total Stock
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at September 1, 1994 $ 195,568 $ 174,926 $ 370,494 $9,000
Net income -- 42,804 42,804 --
Issuance of common stock 5,836 -- 5,836 --
Preferred stock dividends -
$2.375 per share -- (428) (428) --
Common stock dividends -
$1.12 per share -- (30,077) (30,077) --
--------- --------- --------- ------
Balance at August 31, 1995 $ 201,404 $ 187,225 $ 388,629 $9,000
========= ========= ========= ======
Balance at September 1, 1995 $ 201,404 $ 187,225 $ 388,629 $9,000
Net income -- 52,836 52,836 --
Issuance of common stock 5,680 -- 5,680 --
Preferred stock dividends -
$2.375 per share -- (428) (428) --
Common stock dividends -
$1.18 per share -- (32,022) (32,022) --
--------- --------- --------- ------
Balance at August 31, 1996 $ 207,084 $ 207,611 $ 414,695 $9,000
========= ========= ========= ======
BALANCE AT SEPTEMBER 1, 1996 $ 207,084 $ 207,611 $ 414,695 $9,000
NET INCOME -- 59,268 59,268 --
ISSUANCE OF COMMON STOCK 22,719 -- 22,719 --
PREFERRED STOCK DIVIDENDS -
$1.78 PER SHARE -- (321) (321) --
REDEMPTION OF SERIES A PREFERRED STOCK (540) (540) (9,000)
COMMON STOCK DIVIDENDS -
$1.20 PER SHARE -- (33,195) (33,195) --
--------- --------- --------- ------
BALANCE AT AUGUST 31, 1997 $ 229,803 $ 232,823 $ 462,626 $ --
========= ========= ========= ======
</TABLE>
See accompanying notes to consolidated financial statements.
33
<PAGE> 34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS - ONEOK Inc. and subsidiaries (collectively, the Company)
is a diversified energy company engaged in the production, processing, storage,
transportation, distribution and marketing of environmentally clean fuels and
products. The Company's business units are characterized as operating within
either a rate regulated environment (regulated operations) or a nonregulated
environment (nonregulated operations). The regulated business units provide
natural gas distribution and transmission for about 75 percent of Oklahoma and
during 1997 generated approximately 78 percent of operating income before income
taxes. The nonregulated business has segments involved in various aspects of
natural gas marketing, processing and production. The Company's other segment,
whose results of operations are not material, operates and leases the Company's
headquarters building and parking facility.
CONSOLIDATION - The consolidated financial statements include the accounts of
ONEOK Inc. and its wholly owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation.
REGULATION - The regulated operations of the Company are primarily subject to
the rate regulation and accounting requirements of the Oklahoma Corporation
Commission (OCC). Certain other regulated activities of the Company are subject
to regulation by the Federal Energy Regulatory Commission (FERC). Accordingly,
the regulated operations follow the accounting and reporting guidance contained
in Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulations". Allocation of costs and revenues to
accounting periods for ratemaking and regulatory purposes may differ from bases
generally applied by nonregulated companies. Such allocations to meet regulatory
accounting requirements are considered to be generally accepted accounting
principles for regulated utilities provided that there is a demonstrable ability
to recover any deferred costs in future rates.
During the rate-making process, regulatory commissions may require a utility to
defer recognition of certain costs to be recovered through rates over time as
opposed to expensing such costs as incurred. This allows the utility to
stabilize rates over time rather than passing such costs on to the customer for
immediate recovery. This causes certain expenses to be deferred as a regulatory
asset and amortized to expense as it is recovered through rates. Total
regulatory assets resulting from this deferral process are approximately $145
million and $155 million at August 31, 1997 and 1996 respectively. See Note B.
REVENUE RECOGNITION - The Company recognizes revenue when services are rendered
or product is delivered. Major industrial and commercial gas distribution
customers are invoiced as of the end of each month. Certain gas distribution
customers, primarily residential and some commercial, are invoiced on a cycle
basis throughout each month, and the Company accrues unbilled revenues at the
end of each month. Beginning in 1996, the Company's rate tariff for residential
and commercial customers contained a temperature normalization clause that
provided for billing adjustments from actual volumes to normalized volumes
during the winter heating season. Revenues from marketing, processing and
production are recognized on the sales method. Credit is granted to these
customers under customary terms.
REGULATED PROPERTY - Regulated distribution, transmission, and storage property
is stated at cost. Such cost includes personnel costs, general and
administrative costs, and an allowance for funds used during construction. The
allowance for funds used during construction represents the capitalization of
estimated average cost of borrowed funds (8.6 percent, 8.50 percent, and 8.24
percent, in 1997, 1996, and 1995, respectively) used during the construction of
major projects and is recorded as a credit to earnings.
34
<PAGE> 35
Depreciation is calculated using the straight-line method based upon rates
prescribed for ratemaking purposes. The average depreciation rate approximated
3.7 percent in 1997, 3.6 percent in 1996 and 3.7 percent in 1995.
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.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
REMAINING SERVICE
LIFE (YEARS)
- --------------------------------------------------------------------------------
<S> <C> <C>
Distribution property 25 40
Gathering property 33 47
Storage property 5 40
Transmission property 33 47
Other property 24 40
- --------------------------------------------------------------------------------
</TABLE>
PRODUCTION PROPERTY - The Company uses the successful-efforts method to account
for costs incurred in the acquisition and exploration of oil and natural gas
reserves. Costs to acquire mineral interests in proved reserves, and to drill
and equip development wells are capitalized. Geological and geophysical costs
and costs to drill exploratory wells which do not find proved reserves are
expensed. Unproved oil and gas properties which are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of impairment by providing an impairment allowance. The remaining unproved
oil and gas properties are aggregated, and an overall impairment allowance is
provided based on the Company's experience.
Depreciation and depletion are calculated using the unit-of-production method
based upon periodic estimates of proven oil and gas reserves. Undeveloped
properties are amortized based upon remaining lease terms and exploratory and
developmental drilling experience.
OTHER PROPERTY - Gas processing plants and all other properties are stated at
cost. Gas processing plants are depreciated using various rates based on
estimated lives of available gas reserves. All other property and equipment is
depreciated using the straight-line method over its estimated useful life.
INVENTORIES - Materials and supplies are priced at average cost. Noncurrent gas
in storage is classified as property and is priced at cost. Cost of current gas
in storage is determined using the last-in, first-out, (lifo) and first-in,
first-out (fifo) methodology by the regulated and nonregulated operations,
respectively. The estimated replacement cost of current gas in storage using the
lifo method was $63.7 million and $81.5 million at August 31, 1997 and 1996,
respectively.
INCOME TAXES - Deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates applicable to
future years to differences between the financial statement carrying amounts and
the tax bases of existing assets and liabilities. The effect on deferred taxes
of a change in tax rates is deferred and amortized for the OCC regulated
operations and, for nonregulated operations, is recognized in income in the
period that includes the enactment date. The Company continues to amortize
previously deferred investment tax credits on gas distribution and transmission
properties over the period prescribed by the OCC for ratemaking purposes.
COMMODITY PRICE RISK MANAGEMENT - To minimize the risk from market fluctuations
in the price of natural gas and oil, the Company enters into futures
transactions, swaps and options in order to hedge certain natural gas in
storage, existing physical gas purchases or sale commitments, as well as
anticipated sales of natural gas production. In order to qualify as a hedge, the
price movements in the underlying commodity derivatives must be sufficiently
correlated with the hedged transaction. Changes in the market value of these
financial instruments utilized as hedges are (1) recognized as an adjustment of
the carrying value in the case of existing assets and liabilities, (2) included
in the
35
<PAGE> 36
measurement of the transaction that satisfies the commitment in the case of
existing commitments and (3) included in the measurement of the subsequent
transaction in the case of anticipated transactions, whether or not the hedge is
closed out before the date of the anticipated transaction. In cases where
anticipated transactions do not occur, deferred gains and losses are recognized
when such transactions were scheduled to occur. Some of these financial
instruments carry off-balance sheet risk, see "Credit risk and Off-Balance Sheet
Risk" included in Note H.
IMPAIRMENTS - Effective March 1, 1996, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which requires
impairment losses to be recognized for long-lived assets 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. Under SFAS No. 121, the Company now evaluates impairment of
production assets on the lowest possible level, (a field by field basis) rather
than using a total company basis for its proved properties. Primarily due to
downward reserve revisions for certain proven properties, the Company in
accordance with SFAS No. 121, recognized a pre-tax impairment loss of $8.6
million in 1996, such loss is included in depreciation, depletion and
amortization expense. Prior to the adoption of SFAS No. 121, the Company
evaluated impairment of its proven reserves using a discounted cash flow
approach on a total company basis which aggregated all properties for purposes
of determining impairment.
USE OF ESTIMATES - Management has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and the disclosure of
contingent assets and liabilities to prepare these financial statements in
conformity with generally accepted accounting principles. Actual results could
differ from these estimates.
EARNINGS PER COMMON SHARE - The computation of earnings per common share is
based on the weighted average number of shares of common stock outstanding.
Unexercised stock options do not have a material dilutive effect on the reported
amount of earnings per common share.
COMMON STOCK OPTIONS AND AWARDS - Effective September 1, 1996, the Company
adopted the disclosure requirements of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123") which
permits, but does not require, a fair value based method of accounting for
stock-based employee compensation. Alternatively, SFAS 123 allows companies to
continue applying the provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees"("APB 25"), however, such companies
are required to disclose pro forma net income and earnings per share as if the
fair value based method had been applied. The Company has elected to continue to
apply the provisions of APB 25 for the purpose of computing compensation expense
and has provided the pro forma disclosure provisions of SFAS 123 in Note Q.
CASH AND CASH EQUIVALENTS - Items classified as cash equivalents for the purpose
of the Consolidated Statements of Cash Flows include highly liquid temporary
investments, with original maturities of three months or less, in "money market"
or "pooled" investment accounts backed by government securities, bank
certificates of deposit, or bank lines of credit.
RECLASSIFICATION - Certain amounts in the 1996 and 1995 consolidated financial
statements have been reclassified to conform with the 1997 presentation.
36
<PAGE> 37
(B) REGULATORY ASSETS
The following table is a summary of regulatory assets, net of amortization:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
AUGUST 31, 1997 1996
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
<S> <C> <C>
Recoupable take-or-pay settlements $ 95,482 $100,155
Pension costs 29,244 33,426
Postretirement costs other than pensions 8,836 9,386
Postemployment benefit costs 3,327 2,975
Income tax rate exchanges 7,823 8,354
Unamortized gas storage costs -- 957
-------- --------
Regulatory assets, net $144,712 $155,253
- --------------------------------------------------------------------------------
</TABLE>
Certain of the regulatory assets listed above are being recovered through rates,
but the Company is not being allowed to earn a rate of return on the unrecovered
balance. The remaining recovery period is set forth in the table below.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
REMAINING RECOVERY
PERIOD (MONTHS)
- --------------------------------------------------------------------------------
<S> <C>
Postretirement costs other than pension 193
Income tax rate changes - 1990 166
Income tax rate change - 1993 182
- --------------------------------------------------------------------------------
</TABLE>
Postemployment benefit costs are currently being deferred as a regulatory asset
because the methodology of their recovery has not yet been determined in rate
proceedings.
No significant recoupable costs attributable to resolutions of take-or-pay and
pricing issues were incurred in 1997 or 1996. The OCC has authorized recovery of
the take-or-pay settlement costs through a combination of a surcharge to
customers and revenues derived from certain transportation customers.
The pension and postretirement benefit costs previously deferred are currently
being recovered through revenue and are being amortized to expense over a 10 to
18 year period. As discussed in Note G, the OCC also approved recovery of
pension and postretirement benefit costs through rates. The Company anticipates
that postemployment benefit costs will be recovered in future rate filings.
Amortization expense related to regulatory assets was approximately $10.1
million, $11.7 million, and $8.2 million in 1997, 1996, and 1995, respectively.
An additional $2.1 million was recovered through gas purchase expense during
1995.
(C) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE
At August 31, 1997, the Company had a short-term unsecured credit agreement with
several banks pursuant to which the banks have agreed to make loans to the
Company from time to time in an aggregate amount not to exceed $175 million at
any one time for general corporate purposes. The short-term credit agreement
provides a back-up line of credit for short-term debt from other sources in
addition to providing short-term funds. The facility fee requirement for this
line of credit is .0575 percent applied annually to the total line of credit.
Borrowings under the agreement bear interest at offshore IBOR rates plus .1675
percent per annum. No compensating balance requirements existed at August 31,
1997. The Company also has additional credit facilities available through a
master note with Bank of America and a short-term note with NationsBank which
provide an additional $30 million and $25 million in borrowing capability,
respectively. No borrowings are outstanding under these latter two agreements at
August 31, 1997. Maximum short-term debt from all sources as approved by the
Company's Board of Director's is $175 million.
37
<PAGE> 38
Short-term notes payable totaling $45 million at August 31, 1997, and $50.2
million at August 31, 1996, were outstanding. The notes carried average interest
rates of 5.84 percent and 5.61 percent, respectively.
(D) LONG-TERM DEBT
All long-term notes payable at August 31, 1997, are unsecured. The aggregate
current maturities of long-term debt for each of the five years ending August
31, 2002, are $18.9 million; $16.9 million; $16.8 million; $15.4 million; and
$14.7 million, respectively, including $1.1 million each year callable at the
option of the holder.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
AUGUST 31, 1997 1996
(THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------
<S> <C> <C>
Long-Term Notes Payable
5.57% due 1997 $ -- $ 14,000
5.90% due 1998 10,000 10,000
6.20% due 1999 8,000 8,000
6.43% due 2000 5,000 5,000
6.50% due 2001 9,252 --
8.32% due 2007 40,000 40,000
8.44% due 2004 40,000 40,000
8.70% due 2021 34,871 34,871
9.70% due 2019 125,000 125,000
9.75% due 2020 75,000 75,000
--------- --------
Total $ 347,123 $ 351,871
--------- --------
Current maturities of
long-term debt 18,909 15,050
--------- --------
Long-term notes payable $ 328,214 $ 336,821
- -------------------------------------------------------------------------------
</TABLE>
(E) CAPITAL STOCK
The Company has approximately 26 million shares of unrestricted common stock
available for issue. The Company redeemed all of its outstanding shares of
Series A preferred stock at its stated voluntary liquidation value of $53 per
share during the third quarter of fiscal 1997.
The Board has reserved two million shares of the Company's common stock for the
Direct Stock Purchase and Dividend Reinvestment Plan of which 362,518 shares
were issued in 1997 and 192,228 shares were issued in 1996; and has reserved
approximately three million shares for the Thrift Plan for Employees of ONEOK
Inc. and Subsidiaries.
Under the most restrictive covenants of the Company's loan agreements, $205.4
million (88.2 percent) of retained earnings at August 31, 1997, was available to
pay dividends.
(F) INCOME TAXES
The provisions for income taxes are as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Current income taxes
Federal $ 32,207 $ 29,925 $ 34,837
State 5,620 5,150 5,775
--------- --------- ---------
Total current income taxes $ 37,827 $ 35,075 $ 40,612
========= ========= =========
Deferred income taxes
Federal $ (2,551) $ (1,766) $ (13,007)
State (437) (272) (2,263)
--------- --------- ---------
Total deferred income taxes $ (2,988) $ (2,038) $ (15,270)
========= ========= =========
Total provision for income taxes $ 34,839 $ 33,037 $ 25,342
===============================================================================
</TABLE>
38
<PAGE> 39
Following is a reconciliation of the provision for income taxes.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
Pretax income $ 94,107 $ 85,874 $ 68,146
Federal statutory income tax rate 35,00% 35.00% 35.00%
---------- --------- ---------
Provision for federal income tax rate 32,937 30,056 23,851
Amortization of distribution property
investment tax credits (655) (727) (739)
State income taxes, net of credits
and federal tax benefit 2,376 3,548 2,372
Other, net 181 160 (142)
---------- --------- ---------
Actual income tax expenses $ 34,839 $ 33,037 $ 25,342
==================================================================================
</TABLE>
At August 31, 1997, the Company had $1.4 million in deferred investment tax
credits recorded in other deferred credits which will be amortized over the next
two years.
The tax effects of temporary differences that gave rise to significant portions
of the deferred tax assets and liabilities are shown in the accompanying table.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
AUGUST 31, 1997 1996
(THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------
<S> <C> <C>
Deferred Tax Assets
Investment write-down $ -- $ 1,373
Accrued liabilities not deductible until paid 5,629 7,016
Net operating loss carryforwards 760 754
Regulatory assets 2,687 2,601
Other 2,791 2,052
--------- ---------
Total deferred tax assets 11,867 13,796
Valuation allowance for net operating loss
carryforwards expected to expire prior to
utilization 760 754
--------- ---------
Net deferred tax assets 11,107 13,042
Deferred Tax Liabilities
Excess of tax over book depreciation and depletion 138,312 133,207
Investment in joint ventures 1,100 --
Regulatory assets 53,683 60,753
Other 2,698 3,129
--------- ---------
Gross deferred tax liabilities 195,793 197,089
--------- ---------
Net Deferred Tax Liabilities $ 184,686 $ 184,047
==================================================================================
</TABLE>
The Company had remaining net operating loss carry-forwards for state income tax
purposes of approximately $13.4 million at August 31, 1997, which expire, unless
previously utilized, at various dates through the year 2009.
(G) EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN - The Company has a defined benefit retirement plan covering
substantially all employees. Company officers and certain key employees are also
eligible to participate in a supplemental retirement plan.
39
<PAGE> 40
Net pension costs, as determined by an independent actuary, included the
following:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------
THOUSANDS OF DOLLARS 1997 1996 1995
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 5,126 $ 5,957 $ 6,078
Interest cost 23,766 23,525 22,659
Actual return on assets (9,010) (72,138) (27,438)
Net amortization and deferral (16,281) 50,337 6,920
-------------------------------------
Net pension cost $ 3,601 $ 7,681 $ 8,219
===================================================================================
</TABLE>
The Company generally funds pension costs at a level at least equal to the
minimum amount required under the Employee Retirement Income Security Act of
1974. The accompanying table sets forth the funded status of the Company's
plans, as determined by the independent actuary.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
AUGUST 31, 1997 1996
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of vested benefit obligation $(277,266) $(268,296)
Accumulated benefit obligation (291,662) (281,363)
Projected benefit obligation (326,539) (314,866)
Plan assets at fair value, principally equity
securities and an IPG fund 326,384 328,459
------------------------
Plan assets in excess of projected
benefit obligation (155) 13,593
Unrecognized net (gain) loss 15,308 (863)
Unrecognized prior service cost 784 149
Unrecognized net asset (3,272) (3,739)
------------------------
Prepaid pension cost $ 12,665 $ 9,140
====================================================================================
</TABLE>
The projected benefit obligation was determined using an annual discount rate of
7.75 percent for 1997 and for 1996; a long-term rate of return on plan assets of
9 percent and 8 percent for 1997 and 1996, respectively; and an average assumed
long-term annual rate of salary increases of 4 percent for both 1997 and 1996.
OTHER POSTRETIREMENT BENEFIT PLANS - The Company sponsors a defined benefit
health care plan that provides postretirement medical benefits and life and
accidental death and dismemberment benefits to substantially all employees who
reach normal retirement age while working for the Company. The plan is
contributory, with retiree contributions adjusted periodically, and contains
other cost-sharing features such as deductibles and coinsurance. The Company
began funding the plan in September 1996.
The Company elected to delay recognition of the accumulated postretirement
benefit obligation (APBO) of approximately $72.2 million and amortize it over 20
years as a component of net periodic postretirement benefit cost.
Net periodic postretirement benefit cost includes the following components:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
THOUSANDS OF DOLLARS 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C>
Service costs $ 1,744 $ 1,704
Interest costs 5,599 5,668
Actual return on plan assets (184) -
Net amortization and deferral 3,387 3,608
-----------------------
Net periodic postretirement benefit cost $ 10,546 $ 10,980
============================================================================
</TABLE>
40
<PAGE> 41
For measurement purposes, a 8.3 percent annual rate of increase in the per
capita cost of covered medical benefits (i.e., medical cost trend rate) was
assumed for 1997, 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 rate by one percentage point in each
year would increase the accumulated postretirement benefit obligation as of
August 31, 1997, by $6.7 million and the aggregate of the service and interest
cost components of net periodic postretirement benefit cost for the year ended
August 31, 1997, by $0.8 million.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.75 percent at August 31, 1997.
The following table presents the plan's funded status reconciled with amounts
recognized in the Company's consolidated balance sheet.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
AUGUST 31, 1997 1996
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
<S> <C> <C>
Accumulated Postretirement Benefit Obligation
Retirees $(49,840) $(49,500)
Fully eligible active plan participants (3,192) (3,246)
Other active plan participants (22,074) (21,708)
-----------------------
Accumulated postretirement benefit obligation (75,106) (74,454)
Fair value of plan assets 8,150 -
-----------------------
Accumulated postretirement benefit obligation
in excess of plan assets (66,956) (74,454)
Unrecognized transition obligation 51,757 61,341
Unrecognized net gain (5,307) (9,071)
-----------------------
Accrued postretirement benefit cost $(20,506) $(22,184)
===============================================================================
</TABLE>
EMPLOYEE THRIFT PLAN - The Company has a Thrift Plan covering all employees.
Employee contributions are discretionary. Subject to certain limits, employee
contributions are matched by the Company. The annual cost of the plan was $3.4
million in 1997; $3.7 million in 1996; $3.4 million in 1995.
POSTEMPLOYMENT BENEFITS - The Company pays postemployment benefits to former or
inactive employees after employment but before normal retirement.
REGULATORY TREATMENT - The OCC has approved the recovery of 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.
41
<PAGE> 42
(H) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
FINANCIAL INSTRUMENTS - The following table presents the carrying amounts and
fair values of certain of the Company's financial instruments. Fair value is
defined as the amount at which the instrument could be exchanged in a current
transaction between willing parties. The estimated fair value of long term debt
and notes payable have been determined using quoted market prices of same or
similar issues, discounted cash flows and/or rates currently available to the
Company for debt with similar terms and remaining maturities. The fair value of
natural gas and oil swaps, options and futures contracts generally reflect the
estimated amounts that the Company would pay or receive to terminate the
contracts at the reporting date, thereby taking into account the unrealized
gains and losses on open contracts. There is no readily available market for
natural gas swaps. The items presented without a carrying value are off-balance
sheet financial instruments. All of the Company's financial instruments are held
for purposes other than trading.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
APPROXIMATE
(THOUSANDS OF DOLLARS) BOOK VALUE FAIR VALUE
- -------------------------------------------------------------------
<S> <C> <C>
AUGUST 31, 1997
Cash and cash equivalents $ 14,377 $ 14,377
Accounts and notes receivable $ 100,937 $ 100,937
Natural gas swaps -- $ 3,809
Natural gas options -- (273)
Natural gas futures -- (1,700)
Long-term debt and notes payable $ 347,123 $ 379,141
---------- -----------
August 31, 1996
Cash and cash equivalents $ 598 $ 598
Accountants and notes receivable $ 119,338 $ 119,338
Natural gas swaps -- $ 2,924
Natural gas options -- $ 78
Natural gas futures -- $ 1,935
Long-term debt and notes payable $ 351,871 $ 377,383
- -------------------------------------------------------------------
</TABLE>
RISK MANAGEMENT - The Company's gas marketing, processing and production
operations subject the Company's earnings to variability based on fluctuations
in both the market price and transportation costs of natural gas and oil. The
Company's exposure arises from fixed price purchase or sale agreements which
extend for periods of up to 48 months, certain gas storage inventories, and
anticipated sales of oil and gas production. In order to mitigate the financial
risks associated with such activities the Company routinely enters into natural
gas and oil futures contracts, swaps and options, collectively referred to
herein as derivatives. Net open positions in terms of price, volume and
specified delivery point do occur.
The futures contracts are purchased and sold on the New York Mercantile Exchange
(NYMEX ) or the Kansas City Board of Trade (KCBOT) and require the Company to
buy or sell natural gas at a fixed price. Swap agreements generally require one
party to make payments based on the difference between a fixed price or fixed
differential from the NYMEX or KCBOT price while the other party pays a price
based on a published index. Swaps and options allow the Company to commit to
purchase gas at one location and sell it at another location without assuming
unacceptable risk with respect to changes in the price of the gas or the cost of
the intervening transportation. Natural gas options held to hedge price risk
provide the right, but not the requirement, to buy or sell natural gas at a
fixed price. The Company utilizes options to limit overall price risk exposure.
None of these derivatives are held for speculative purposes and, in general, the
Company's risk management policy requires that positions taken with derivatives
be offset by positions in physical transactions or other derivatives.
The total notional value of futures contracts purchased and sold is $70.5
million and $76.8 million, respectively, at August 31, 1997. The term "notional
amount" refers to the current contract unit price times the contract volume for
the relevant derivative. In general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative
42
<PAGE> 43
of the Company's level of activity in such derivatives, although the amounts at
risk are significantly smaller because, in general, changes in market value of
these derivatives are offset by changes in the value associated with the
underlying physical transaction or other derivatives.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(VOLUMES IN MMcf, THOUSANDS OF DOLLARS)
ESTIMATED FAIR
VOLUME VOLUME MARKET VALUE
AUGUST 31, 1997 PURCHASED SOLD GAIN (LOSS)(A)
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Options 2,000 11,960 $ (273)
Swaps 72,414 62,908 $ 3,809
Futures 30,420 32,010 $(1,700)
- -----------------------------------------------------------------------------
AUGUST 31, 1996
- -----------------------------------------------------------------------------
Options -- 1,335 $ 78
Swaps 178,632 178,432 $ 2,924
Futures 54,680 53,460 $ 1,935
- -----------------------------------------------------------------------------
</TABLE>
(A) Represents the estimated amount which would have been recognized upon
termination of the relevant derivatives as of the date indicated. The amount
which is ultimately charged or credited to earnings is affected by subsequent
changes in the market value of these derivatives.
NYMEX and KCBOT-traded futures and option contracts are guaranteed by NYMEX and
KCBOT and have nominal credit risk. All other derivative transactions expose the
Company to off-balance sheet risk in the event of non-performance by the
counterparts. In order to minimize this risk, the Company analyzes each
counterpart's financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of these limits on an
on-going basis. Swap agreements are generally settled at the expiration of the
contract term and may be subject to margin requirements with the counterparty.
NYMEX and KCBOT-traded futures and options contracts require daily cash
settlement in margin accounts with brokers.
(I) SEGMENT INFORMATION
The Company conducts its business through five reporting segments: (1) Oklahoma
Natural Gas, which includes gathering, transmission, storage, and distribution
of natural gas, transportation of gas for others, and leasing pipeline capacity;
(2) Marketing, which purchases and markets natural gas; (3) Processing, which
includes extracting and selling natural gas liquids; (4)Production, which
includes exploiting, producing, and selling natural gas and oil; and (5) Other,
which includes operating and leasing the Company's headquarters building and a
related parking facility.
43
<PAGE> 44
Following is information relative to the Company's operations in different
segments.
<TABLE>
<CAPTION>
OKLAHOMA
NATURAL
(MILLIONS OF DOLLARS) GAS MARKETING PROCESSING PRODUCTION OTHER TOTAL
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1997
Sales to unaffiliated customers $ 598.4 $ 459.6 $ 71.6 $ 27.2 $ 5.1 $ 1,161.9
Intersegment sales 1.1 23.5 15.5 14.0 5.2 59.3
---------- --------- --------- --------- --------- ----------
Total revenues $ 599.5 $ 483.1 $ 87.1 $ 41.2 $ 10.3 $ 1,221.2
---------- --------- --------- --------- --------- ----------
Operating income (loss)
before income taxes $ 100.4 $ 7.8 $ 12.9 $ 8.7 $ (1.0) $ 128.8
Identifiable assets $ 1,026.3 $ 63.8 $ 36.0 $ 100.1 $ 11.2 $ 1,237.4
Depreciation, depletion, and
amortization $ 51.4 $ 0.5 $ 2.4 $ 19.9 $ 0.3 $ 74.5
Capital expenditures $ 67.7 $ 0.4 $ 10.6 $ 32.9 $ 0.4 $ 112.0
=================================================================================================================================
1996
Sales to unaffiliated customers $ 538.2 $ 598.3 $ 58.4 $ 25.5 $ 4.0 $ 1,224.4
Intersegment sales 2.2 15.5 12.7 7.9 5.4 43.7
---------- --------- --------- --------- --------- ----------
Total revenues $ 540.4 $ 613.8 $ 71.1 $ 33.4 $ 9.4 $ 1,268.1
---------- --------- --------- --------- --------- ----------
Operating income (loss) before
interest and income taxes $ 97.3 $ 12.9 $ 9.0 $ 2.8 $ (1.0) $ 121.0
Identifiable assets $ 1,019.4 $ 71.2 $ 26.7 $ 73.2 $ 29.4 $ 1,219.9
Depreciation, depletion, and
amortization $ 50.8 $ 0.5 $ 2.0 $ 19.2 $ 0.4 $ 72.9
Capital expenditures $ 42.9 $ 0.4 $ 5.2 $ 46.7 $ 0.2 $ 95.4
=================================================================================================================================
1995
Sales to unaffiliated customers $ 594.9 $ 266.4 $ 64.9 $ 24.1 $ 3.9 $ 954.2
Intersegment sales 1.8 62.9 0.0 0.8 5.7 71.2
---------- --------- --------- --------- --------- ----------
Total revenues $ 596.7 $ 329.3 $ 64.9 $ 24.9 $ 9.6 $ 1,025.4
---------- --------- --------- --------- --------- ----------
Operating income (loss)
before income taxes $ 91.6 $ 4.8 $ 6.3 $ 3.6 $ (0.8) $ 105.5
Identifiable assets $ 1,023.0 $ 41.4 $ 25.2 $ 60.0 $ 31.6 $ 1,181.2
Depreciation, depletion, and
amortization $ 41.3 $ 0.1 $ 1.8 $ 10.0 $ 0.3 $ 53.5
Capital expenditures $ 55.8 $ 0.9 $ 1.2 $ 25.0 $ 0.1 $ 83.0
=================================================================================================================================
</TABLE>
(J) COMMITMENTS AND CONTINGENCIES
LEASES - The initial lease term on the Company's headquarters building, ONEOK
Plaza, is for 25 years, expiring in 2009, with six five-year renewal options. At
the end of the initial term or any renewal period, the Company can purchase the
property at its fair market value. Rent for the lease accrues annually at $6.8
million a year until 2009. Rent payments were $5.8 million for 1997, 1996, and
1995. Estimated future minimum rental payments for the lease are $5.8 million
for each of the years ended August 31, 1998 through 1999, $7.6 million for the
year ended August 31, 2000, $9.3 million for each of the years ended August 31,
2001 through 2009.
44
<PAGE> 45
The Company has the right to sublet excess office space in ONEOK Plaza. The
Company received $2.7 million, $2.5 million, and $2.4 million in rental revenue
during 1997, 1996, and 1995, respectively, for various subleases. Estimated
minimum future rental payments to be received under existing contracts for
subleases are: $2.6 million in 1998; $2.4 million in 1999; $2.0 million in 2000,
$1.9 million in 2001; $1.9 million in 2002 and a total of $3.6 million
thereafter.
OTHER - The Company is involved in claims and legal actions arising in the
ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a materially adverse effect on the
Company's financial condition, results of operation, or cash flows.
(K) OIL AND GAS PRODUCING ACTIVITIES
The following is historical revenue and cost information relating to the
Company's production operations:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Capitalized costs at end of year:
Unproved properties $ 2,994 $ 11,330 $ 5,030
Proved properties 155,208 129,035 111,459
--------------------------------------
Total Capitalized Costs 158,202 140,365 116,489
Accumulated depreciation,
depletion, and amortization 83,457 74,129 65,376
--------------------------------------
Net Capitalized Costs $ 74,745 $ 66,236 $ 51,113
======================================
Costs incurred during the year:
Property acquisition costs
(unproved) $ 174 $ 231 $ 926
Exploration costs $ 71 $ 601 $ 1,228
Development costs $ 6,683 $ 2,811 $ 4,839
Purchase of minerals in place $ 21,489 $ 43,064 $ 15,099
- ---------------------------------------------------------------------------
</TABLE>
The accompanying schedule presents the results of operation for the Company's
oil and gas producing activities. The results exclude general office overhead
and interest expense attributable to oil and gas production.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Net revenues from production:
Sales to unaffiliated customers $ 24,141 $ 17,325 $ 18,427
Gas sold to affiliates 14,018 7,856 2,372
--------------------------------------
Net revenues from production 38,159 25,181 20,799
--------------------------------------
Production costs 7,918 5,494 4,565
Exploration expenses (12) 574 680
Depreciation, depletion,
amortization 19,246 18,552 9,447
Income tax expense 4,258 171 2,265
--------------------------------------
Total expenses 31,410 24,791 16,957
--------------------------------------
Results of operations from
producing activities $ 6,749 $ 390 $ 3,842
===========================================================================
</TABLE>
45
<PAGE> 46
(L) OIL AND GAS RESERVES (UNAUDITED)
Following are estimates of the Company's proved oil and gas reserves, net of
royalty interests and changes therein, for the 1997, 1996, and 1995 fiscal
years.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
OIL GAS
PROVED RESOURCES (Mbbls) (MMcf)
- --------------------------------------------------------------------------------
<S> <C> <C>
August 31, 1994 2,284 32,370
Revisions of prior estimates 579 84
Extensions, discoveries, and other additions 241 4,002
Purchase of minerals in place 637 11,931
Sales of minerals in place (28) (386)
Production (466) (8,775)
-------- -------
August 31, 1995 3,247 39,226
Revisions of prior estimates (59) (1,258)
Extensions, discoveries, and other additions 41 5,089
Purchase of minerals in place 928 42,347
Sales of minerals in place (1,712) (1,930)
Production (435) (9,406)
-------- -------
AUGUST 31, 1996 2,010 74,068
REVISIONS OF PRIOR ESTIMATES 115 2,108
DISCOVERIES, AND OTHER ADDITIONS 111 3,009
PURCHASE OF MINERALS IN PLACE 155 19,214
SALES OF MINERALS IN PLACE (41) (515)
PRODUCTION (336) (14,565)
-------- -------
AUGUST 31, 1997 2,014 83,319
======== =======
Proved developed reserves:
August 31, 1995 3,068 36,946
August 31, 1996 1,642 60,497
AUGUST 31, 1997 1,615 62,115
- --------------------------------------------------------------------------------
</TABLE>
The Company emphasizes that the volumes of reserves shown above are estimates,
which, by their nature, are subject to later revision. The estimates are made by
the Company utilizing all available geological and reservoir data as well as
production performance data. These estimates are reviewed annually and revised,
either upward or downward, as warranted by additional performance data.
(M) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
Estimates of the standard measure of discounted future cash flows from proved
reserves of oil and natural gas shown in the accompanying table are based on
prices at the end of the year. Gas prices are escalated only for fixed and
determinable amounts under provisions of applicable regulations in some
contracts. These estimated future cash flows are reduced by estimated future
development and production costs based on year-end cost levels, assuming
continuation of existing economic conditions, and by estimated future income tax
expense. This 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.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Future cash inflows $218,708 $173,166 $111,370
Future production and development costs 67,962 53,491 29,684
Future income tax expense 33,514 21,245 16,375
-------- -------- --------
Future net cash flows 117,232 98,430 65,311
10 percent annual discount for estimated
timing of cash flows 40,621 31,114 17,484
-------- -------- --------
Standardized measure of discounted future
net cash flows relating to oil and gas
reserves $ 76,611 $ 67,316 $ 47,827
================================================================================
</TABLE>
46
<PAGE> 47
The changes in standardized measure of discounted future net cash flows relating
to proved oil and gas reserves are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Beginning of year $67,316 $47,827 $40,229
Changes resulting from:
Sales of oil and gas produced, net of
production costs (30,241) (19,687) (16,234)
Net changes in price, development, and
production costs 12,478 4,054 (4,874)
Extensions, discoveries, additions, and
improved recovery, less related costs 5,047 6,056 6,377
Purchases of minerals in place 19,747 42,999 14,707
Sales of minerals in place (1,000) (20,962) (871)
Revisions of previous quantity estimates 3,159 (114) 5,520
Accretion of discount 8,084 3,885 5,107
Net change in income taxes (7,372) (2,538) (274)
Other, net (607) 5,796 (1,860)
------- ------- -------
End of year $76,611 $67,316 $47,827
================================================================================
</TABLE>
(N) QUARTERLY FINANCIAL DATA (UNAUDITED)
Total operating revenues are consistently greater from November through May due
to the large volume of natural gas sold to customers for heating. A summary of
the unaudited quarterly results of operations for 1997 and 1996 follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Quarter
--------------------------------------------------------
1997 First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
<S> <C> <C> <C> <C>
Operating revenues
Regulated $113,246 $282,794 $128,970 $ 73,380
Nonregulated $135,506 $190,859 $102,657 $ 134,515
Operating income $ 28,678 $ 71,057 $ 29,924 $ (867)
Net income (loss) $ 12,174 $ 38,241 $ 13,769 $ (4,916)
Earnings per share of common stock $ 0.44 $ 1.39 $ 0.49 $ (0.19)
Dividends per share of common share $ 0.30 $ 0.30 $ 0.30 $ 0.30
Average shares of common stock
outstanding (thousands) 27,305 27,378 27,897 28,018
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Quarter
--------------------------------------------------------
1996 First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
<S> <C> <C> <C> <C>
Operating revenues
Regulated $104,858 $227,539 $131,396 $ 74,376
Nonregulated $133,602 $237,201 $158,286 $ 157,087
Operating income $ 22,815 $ 71,508 $ 27,835 $ (1,123)
Net income (loss) $ 8,423 $ 38,543 $ 11,707 $ (5,837)
Earnings per share of common stock $ 0.31 $ 1.42 $ 0.42 $ (0.22)
Dividends per share of common share $ 0.29 $ 0.29 $ 0.30 $ 0.30
Average shares of common stock
outstanding (thousands) 27,023 27,100 27,186 27,232
===================================================================================================================
</TABLE>
47
<PAGE> 48
(O) SUPPLEMENTAL CASH FLOW INFORMATION
The following table is supplemental information relative to the Company's cash
flows for the years ended August 31, 1997, 1996 and 1995.
In connection with the acquisition of PSEC, Inc. and other oil and gas
properties, the Company issued common stock of $9.8 million, debt of $9.2
million and recognized a deferred tax liability of $3.5 million. The
acquisitions were accounted for in accordance with the purchase method.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1997 1996 1995
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Paid During the Year
Interest (including amount capitalized) $ 39,993 $ 35,122 $ 37,642
Income taxes $ 34,618 $ 40,642 $ 34,513
Noncash Transactions:
Gas received as payment in kind $ 478 $ 2,395 $ 86,033
Issuance of common stock related to:
Stock Performance Plan - $ 1,144 -
Acquisition of gas marketing
partnership - - $ 5,836
Dividend reinvestment plan $ 5,482 $ 4,536 -
Distribution of net assets
from partnership - $ 14,625 -
- ------------------------------------------------------------------------------------
</TABLE>
(P) SUBSEQUENT EVENTS
In December 1996, the Company and Western Resources, Inc. (Western) announced a
strategic alliance combining the natural gas assets of both companies. The
agreement provides for the Company to own and operate the natural gas assets of
Western located in Kansas and northeast Oklahoma. Western will own approximately
three million shares of common stock and 19 million shares of Series A
convertible preferred stock making Western the largest shareholder of the
Company. The preferred stock will be non-voting and convertible into common
shares only under certain circumstances. Additionally, a shareholder agreement
containing standstill provisions prevents Western from increasing their position
in the Company and restricts the conditions under which Western can vote any
common shares created from conversion of its preferred stock.
The agreement was closed on November 26, 1997, and effective on that same date.
Under the agreement, Western formed a new wholly owned subsidiary, WAI, Inc.
(WAI). WAI did not engage in any activities other than activities related to the
alliance. Immediately prior to the effective time of the merger, Western
contributed all of the assets covered by the agreement to WAI. The Company then
merged with and into WAI, with WAI as the surviving corporation, whereupon WAI's
name changed to ONEOK, Inc. (New ONEOK). The Company's common stock outstanding
at the merger was converted on a one-for-one basis into shares of NEW ONEOK
Common Stock.
The merger will be accounted for under the purchase method of accounting. For
purposes of applying the purchase method of accounting, ONEOK is deemed to be
the acquiring enterprise and WAI is deemed to be the acquired enterprise without
regard to which enterprise is the surviving enterprise.
(Q) STOCK BASED COMPENSATION
On August 17, 1995, the Company adopted the Key Employee Stock Plan (Plan). The
Plan provides for the granting of incentive stock options, fixed stock options,
and stock bonus awards to key employees. Under the Plan, options may be granted
by the Executive Compensation Committee (the Committee) at any time within ten
years thereafter (before August 17, 2005). Options may be granted which are not
exercisable until a fixed future date or in installments. The Plan also provides
for restored options in the event that the optionee surrenders shares of common
stock which the optionee already owns in full or partial payment of the options
price under this option and/or surrenders shares of common stock to satisfy
withholding tax obligations incident to the exercise of this option. A restored
option has an option price equal to the fair market value of the common stock on
the date on which the exercise of the option resulted in the grant of the
restored option. The Company has reserved 1,000,000 shares of common stock for
the Plan.
48
<PAGE> 49
Options become void upon voluntary termination of employment other than
retirement. In the event of retirement or involuntary termination, the optionee
may exercise the option within three months. In the event of death, the option
may be exercised by the personal representative of the optionee within a period
to be determined by the Committee and stated in the option.
Options issued to date can be exercised after one year from grant date and must
be exercised no more than ten years after grant date. Activity to date has been
as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------
NUMBER WEIGHTED AVERAGE
OF SHARES EXERCISE PRICE
- -----------------------------------------------------------------------
<S> <C> <C>
OUTSTANDING AT SEPTEMBER 1, 1995 0 $0.00
Granted 107,400 $23.69
- -----------------------------------------------------------------------
OUTSTANDING AT AUGUST 31, 1996 107,400 $23.69
Granted 100,700 $26.88
Exercised 20,700 $23.69
Terminated 2,200 $26.69
Reissued 4,147 $30.71
- ------------------------------------------------------------------------
OUTSTANDING AT AUGUST 31, 1997 189,347 $25.54
- ------------------------------------------------------------------------
</TABLE>
At August 31, 1997, the range of exercised prices and the weighted average
remaining contractual life of outstanding options was $23.69 to $26.88 and 8.7
years, respectively. The total number of options exercisable at that date was
88,646. No options were exercisable at August 31, 1996.
Persons granted an option must agree to remain in the service of the Company for
a period of two years from the date of granting of the option or until earlier
retirement, total disability, or death.
In 1995, the Company authorized the Employee Stock Purchase Plan and reserved
350,000 shares of common stock for it. Almost all of the full-time employees are
eligible to participate. Under the terms of the plan, employees can choose to
have up to ten percent of their annual earnings withheld to purchase the
Company's common stock. The Committee may allow contributions to be made by
other means provided that in no event will contributions from all means exceed
ten percent of the employee's annual earnings. The purchase price of the stock
is 85 percent of the lower of its beginning-of-year or end-of-year market price.
Approximately 55 percent of the eligible employees participated the first year.
Under the plan, the Company sold 107,080 shares in December 1996.
The Company continues to apply Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees"(APB 25) in accounting for both plans
and accordingly, no compensation has been recognized in the consolidated
financial statements. Had the Company applied the provisions of SFAS 123 to
determine the Pro forma compensation cost of options granted, the Company's net
income and earnings per share would have been as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------
1997 1996
- ------------------------------------------------
<S> <C> <C>
Net Income (000's)
As reported $59,268 $52,836
Pro forma $58,247 $52,013
Earnings per share
As reported $2.13 $1.93
Pro forma $2.10 $1.90
================================================
</TABLE>
The fair value of each option granted is estimated based on the Black-Scholes
model. Based on previous stock performance, volatility is estimated to be .2264.
Dividend yield is estimated to be 1.20 with a risk-free interest rate of 6.590
percent and 5.947 percent in 1997 and 1996, respectively.
49
<PAGE> 50
Expected life ranged from 1 to 10 years based upon experience to date and the
make-up of the optionees. Fair value of options granted under the Plan was
$27.125 and $23.690 for 1997 and 1996, respectively.
The Stock Performance Plan expired in 1996. During 1995, $1.9 million was
expensed and 48,414 shares of common stock were issued in conjunction with this
predecessor plan. No amounts were expensed in 1994.
50
<PAGE> 51
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS OF THE
REGISTRANT
(A) DIRECTORS OF THE REGISTRANT
Information concerning the directors of the Company is shown in the 1997
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 1996 definitive Proxy Statement, which is incorporated
herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is shown in the 1997 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 on security ownership of certain beneficial owners is shown in
the 1997 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
1997 definitive Proxy Statement, which is incorporated herein by this
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
51
<PAGE> 52
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) Third Restated Certificate of Incorporation of ONEOK Inc.,
incorporated by reference from Form 10-K dated August 31, 1994.
(3)(b) By-Laws of ONEOK Inc. as Amended, incorporated by reference from
Form 10-K dated August 31, 1994.
(4)(a) Article "Fourth" of Third Restated Certificate of Incorporation
of ONEOK Inc. (Preferred Stock, Preference Stock, and Common
Stock), pages 48 through 70, incorporated by reference from Form
10-K dated August 31, 1994.
(4)(b) Indenture dated November 28, 1989, between ONEOK Inc. and
Security Pacific National Bank, incorporated by reference from
Form S-3 Registration Statement No. 33-31979.
(4)(c) Indenture and First Supplemental Indenture dated December 1,
1990, between ONEOK Inc. and Security Pacific National Bank,
incorporated by reference from Form 10-K dated August 31, 1991.
(4)(d) Second Supplemental Indenture dated October 1, 1991, between
ONEOK Inc. and Security Pacific National Bank, incorporated by
reference from Form 10-K dated August 31, 1991.
NOTE: Certain instruments defining the rights of holders of
long-term debt are not being filed as exhibits hereto pursuant
to Item 601(b)(4)(iii) of Regulation S-K. The Company agrees to
furnish copies of such agreements to the SEC upon request.
(4)(e) Rights Agreement between ONEOK Inc. and Chase Manhattan Bank,
N.A. dated March 31, 1988, incorporated by reference from Form
8-A Registration Statement dated March 1988.
(10)(a) ONEOK Inc. Stock Performance Plan, incorporated by reference
from the 1991 Definitive Proxy Statement.
(10)(b) Unfunded Excess Benefit Plan of ONEOK Inc., incorporated by
reference from the 1991 Definitive Proxy Statement.
(10)(c) Termination Agreement between ONEOK Inc. and ONEOK Inc.
Executives dated January 20, 1984, incorporated by reference
from Form 10-K dated August 31, 1984.
(10)(d) Indemnification Agreement between ONEOK Inc. and ONEOK Inc.
Officers and Directors, incorporated by reference from Form 10-K
dated August 31, 1987.
(10)(e) Ground Lease Between ONEOK Leasing Company and Southwestern
Associates dated May 15, 1983, incorporated by reference from
Form 10-K dated August 31, 1983.
52
<PAGE> 53
(10)(f) First Amendment to Ground Lease between ONEOK Leasing Company
and Southwestern Associates dated October 1, 1984, incorporated
by reference from Form 10-K dated August 31, 1984.
(10)(g) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May
15, 1983, incorporated by reference from Form 10-K dated August
31, 1983.
(10)(h) First Amendment to Sublease between RMZ Corp. and ONEOK Leasing
Company dated October 1, 1984, incorporated by reference from
Form 10-K dated August 31, 1984.
(10)(i) ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas
Company dated August 31, 1984, incorporated by reference from
Form 10-K dated August 31, 1985.
(10)(j) Credit Agreement between ONEOK Inc. and Bank of America National
Trust and Savings Association, dated August 20, 1993,
incorporated by reference from Form 10-K dated August 31, 1994.
(10)(k) First Amendment to Credit Agreement between ONEOK Inc. and Bank
of America National Trust and Savings Association, dated August
18, 1994, incorporated by reference from Form 10-K dated August
31, 1994.
(10)(l) Second Amendment to Credit Agreement between ONEOK Inc. and Bank
of America National Trust and Savings Association, dated August
17, 1995, incorporated by reference from 10-K dated August 31,
1995.
(10)(m) Private Placement Agreement between 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 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) Third Amendment to Credit Agreement between ONEOK Inc. and Bank
of America National Trust and Savings Association, dated August
15, 1996, incorporated by reference from Form 10-K dated August
31, 1996.
(10)(p) Fourth Amendment to Credit Agreement between ONEOK Inc. and Bank
of America National Trust and Savings Association, dated August
13, 1997, filed herewith on pages 59 through 68.
(10)(q) Credit Agreement between ONEOK Inc. and Bankers Trust Company,
dated August 1, 1997, filed herewith on pages 69 through 75.
(21) Required information concerning the registrant's subsidiaries is
included in Item 1. of this Form 10-K.
(27) Financial Date Schedule
(99)(a) History of Gas Pricing, incorporated by reference from Form 10-K
dated August 31, 1993.
(99)(b) Joint Stipulation, Cause No. PUD 940000477, Oklahoma Corporation
Commission (June 1, 1995), incorporated by reference from Form
8-K dated June 19, 1995.
53
<PAGE> 54
(2) Financial Statements Page No.
(a) Independent Auditors' Report 28
(b) Consolidated Statements of Income for the
years ended August 31, 1996, 1995, and 1994 29
(c) Consolidated Balance Sheets at August 31, 1996 and 1995 30-31
(d) Consolidated Statements of Cash Flows for the
years ended August 31, 1996, 1995, and 1994 32
(e) Consolidated Statements of Shareholders' Equity
for the years ended August 31, 1996, 1995, and 1994 33
(f) Notes to Consolidated Financial Statements 34-50
(3) Financial Statement Schedules
None.
(B) REPORTS ON FORM 8-K
November 26, 1997 - Strategic alliance with Western Resources become
effective.
April 25, 1997 - ONEOK Board member Dr. G. Rainey Williams death on April
20, 1997.
December 23, 1996 - announcement of strategic alliance with Western
Resources on December 12, 1996.
OTHER MATTERS
For the purpose of complying with the amendments to the rules governing Form S-8
(effective July 13, 1990) under the Securities Act of 1933, the undersigned
registrant hereby undertakes as follows, which undertaking shall be incorporated
by reference in registrant's Registration Statements on Form S-8, Registration
Nos. 33-04177 (filed May 21, 1996), 33-04179 (filed May 21, 1996), and 33-06857
(filed June 26, 1996):
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers, and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as
expressed in the Act and is, therefore, unenforceable. In the event that a
claim for indemnification against such liabilities (other than the payment
by the registrant of expenses incurred or paid by a director, officer, or
controlling person of the registrant in the successful defense of any
action, suit, or proceeding) is asserted by such director, officer, or
controlling person in connection with the securities being registered, the
registrant will, unless in the opinion of its Counsel the matter has been
settled by a controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against
public policy as expressed by the Act and will be governed by the final
adjudication of such issue.
54
<PAGE> 55
SIGNATURE
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 26th day of
November, 1997.
ONEOK Inc.
Registrant
By: J. D. Neal
----------------------------------------
J. D. Neal
Vice President, Chief Financial Officer,
and Treasurer (Principal Financial and
Accounting Officer)
55
<PAGE> 56
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated, on the 26th day of November, 1997.
LARRY W. BRUMMETT D. L. KYLE
- ------------------------------ ----------------------------------------
Larry W. Brummett D. L. Kyle
Chairman of the Board, Director
President, Chief Executive
Officer, and Director
B. H. MACKIE
----------------------------------------
E. G. ANDERSON B. H. Mackie
- ------------------------------ Director
E. G. Anderson
Director
J. D. NEAL
----------------------------------------
W. M. BELL J. D. Neal
- ------------------------------ Vice President, Chief
W. M. Bell Financial Officer, and
Director Treasurer (Principal Financial
and Accounting Officer)
D. R. CUMMINGS
- ------------------------------ D. A. NEWSOM
D. R. Cummings ----------------------------------------
Director D. A. Newsom
Director
W. L. FORD
- ------------------------------ G. D. PARKER
W. L. Ford ----------------------------------------
Director G. D. Parker
Director
J. M. GRAVES
- ------------------------------ J. D. SCOTT
J. M. Graves J. D. Scott
Director ----------------------------------------
Director
S. J. JATRAS
- ------------------------------ S. L. YOUNG
S. J. Jatras ----------------------------------------
Director S. L. Young
Director
56
<PAGE> 57
EXHIBITS INDEX
(3)(a) Third Restated Certificate of Incorporation of ONEOK Inc., incorporated
by reference from Form 10-K dated August 31, 1994.
(3)(b) By-Laws of ONEOK Inc. as Amended, incorporated by reference from Form
10-K dated August 31, 1994.
(4)(a) Article "Fourth" of Third Restated Certificate of Incorporation of ONEOK
Inc. (Preferred Stock, Preference Stock, and Common Stock), pages 48
through 70, incorporated by reference from Form 10-K dated August 31,
1994.
(4)(b) Indenture dated November 28, 1989, between ONEOK Inc. and Security
Pacific National Bank, incorporated by reference from Form S-3
Registration Statement No. 33-31979.
(4)(c) Indenture and First Supplemental Indenture dated December 1, 1990,
between ONEOK Inc. and Security Pacific National Bank, incorporated by
reference from Form 10-K dated August 31, 1991.
(4)(d) Second Supplemental Indenture dated October 1, 1991, between ONEOK Inc.
and Security Pacific National Bank, incorporated by reference from Form
10-K dated August 31, 1991.
NOTE: Certain instruments defining the rights of holders of long-term
debt are not being filed as exhibits hereto pursuant to Item
601(b)(4)(iii) of Regulation S-K. The Company agrees to furnish copies
of such agreements to the SEC upon request.
(4)(e) Rights Agreement between ONEOK Inc. and Chase Manhattan Bank, N. A.
dated March 31, 1988, incorporated by reference from Form 8-A
Registration Statement dated March 1988.
(10)(a) ONEOK Inc. Stock Performance Plan, incorporated by reference from the
1991 Definitive Proxy Statement.
(10)(b) Unfunded Excess Benefit Plan of ONEOK Inc., incorporated by reference
from the 1991 Definitive Proxy Statement.
(10)(c) Termination Agreement between ONEOK Inc. and ONEOK Inc. Executives dated
January 20, 1984, incorporated by reference from Form 10-K dated August
31, 1984.
(10)(d) Indemnification Agreement between ONEOK Inc. and ONEOK Inc. Officers and
Directors, incorporated by reference from Form 10-K dated August 31,
1987.
(10)(e) Ground Lease Between ONEOK Leasing Company and Southwestern Associates
dated May 15, 1983, incorporated by reference from Form 10-K dated
August 31, 1983.
(10)(f) First Amendment to Ground Lease between ONEOK Leasing Company and
Southwestern Associates dated October 1, 1984, incorporated by reference
from Form 10-K dated August 31, 1984.
57
<PAGE> 58
(10)(g) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983,
incorporated by reference from Form 10-K dated August 31, 1983.
(10)(h) First Amendment to Sublease between RMZ Corp. and ONEOK Leasing Company
dated October 1, 1984, incorporated by reference from Form 10-K dated
August 31, 1984.
(10)(i) ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas Company
dated August 31, 1984, incorporated by reference from Form 10-K dated
August 31, 1985.
(10)(j) Credit Agreement between ONEOK Inc. and Bank of America National Trust
and Savings Association, dated August 20, 1993, incorporated by
reference from Form 10-K dated August 31, 1994.
(10)(k) First Amendment to Credit Agreement between ONEOK Inc. and Bank of
America National Trust and Savings Association, dated August 18, 1994,
incorporated by reference from Form 10-K dated August 31, 1994.
(10)(l) Second Amendment to Credit Agreement between ONEOK Inc. and Bank of
America National Trust and Savings Association, dated August 17, 1995,
incorporated by reference from 10-K dated August 31, 1995.
(10)(m) Private Placement Agreement between 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 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) Third Amendment to Credit Agreement between ONEOK Inc. and Bank of
America National Trust and Savings Association, dated August 15, 1996,
incorporated by reference from Form 10-K dated August 31, 1996.
(10)(p) Fourth Amendment to Credit Agreement between ONEOK Inc. and Bank of
America National Trust and Savings Association, dated August 13, 1997,
filed herewith on pages 59 through 68.
(10)(q) Credit Agreement between ONEOK Inc. and Bankers Trust Company, dated
August 1, 1997, filed herewith on pages 69 through 75.
(21) Required information concerning the registrant's subsidiaries is
included in Item 1. of this Form 10-K.
(27) Financial Date Schedule
(99)(a) History of Gas Pricing, incorporated by reference from Form 10-K dated
August 31, 1993.
(99)(b) Joint Stipulation, Cause No. PUD 940000477, Oklahoma Corporation
Commission (June 1, 1995), incorporated by reference from Form 8-K dated
June 19, 1995.
58
<PAGE> 1
EXHIBIT (10)(p)
FOURTH AMENDMENT TO CREDIT AGREEMENT
THIS FOURTH AMENDMENT TO CREDIT AGREEMENT is made and dated as of August 13,
1997 (the "Fourth Amendment") among ONEOK INC., a Delaware corporation (the
"Company"), the financial institutions party to the Credit Agreement
(collectively, the "Banks") referred to below, and BANK OF AMERICA NATIONAL
TRUST AND SAVINGS ASSOCIATION, as Agent (the "Agent"), and amends that certain
Credit Agreement dated as of August 20, 1993, among the Company, the Banks and
the Agent, as amended by a First Amendment dated as of August 18, 1994, a Second
Amendment dated as of August 17, 1995 and a Third Amendment dated as of August
15, 1996 (as so amended or modified from time to time, the "Agreement").
RECITALS
The Company has requested that the Agreement be amended, and the Banks and the
Agent are willing to do so on the terms and conditions set forth herein.
NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of
which are hereby acknowledged, the parties hereby agree as follows:
1. Terms. All terms used herein shall have the same meanings as in the
Agreement unless otherwise defined herein. All references to the
Agreement shall mean the Agreement as hereby amended.
2. Amendments. The Borrower, the Banks and the Agent hereby agree to amend
the Agreement as follows:
2.1 The definition of "Maturity Date" in Section 1.1 of the
Agreement is hereby amended by deleting "August 13, 1997" and
inserting "August 12, 1998" in lieu thereof.
2.2 The definition of "Offshore Applicable Margin" in Section 1.1 of
the Agreement shall be amended and restated in its entirety as
follows:
"Offshore Applicable Margin" means, with respect to Offshore
Rate Loans, 0.1675% per annum."
2.3 Section 2.10(b) shall be amended by deleting ".075%" and
inserting ".0575%" in lieu thereof.
2.4 Section 5.5 shall be amended by deleting "August 31, 1995" and
inserting "August 31, 1996" and by deleting "November 30, 1995,
February 28, 1996 and May 31, 1996" and inserting "November 30,
1996, February 28, 1997 and May 31, 1997" in lieu thereof.
2.5 Section 5.11(b) shall be amended by deleting "August 31, 1995"
and inserting "August 31, 1996" in lieu thereof.
2.6 Schedules 1.1 and 3 attached to the Credit Agreement are hereby
deleted and Schedule 1.1 and 3 attached to this Fourth Amendment
are inserted in lieu thereof.
3. Representations and Warranties. The Company represents and warrants to
Banks and Agent that, on and as of the date hereof, and after giving
effect to this Fourth Amendment:
3.1 Authorization. The execution, delivery and performance of this
Fourth Amendment have been duly authorized by all necessary
corporate action by the Company and this Fourth Amendment has
been duly executed and delivered by the Company.
59
<PAGE> 2
3.2 Binding Obligation. This Fourth Amendment is the legal, valid
and binding obligation of Company, enforceable against the
Company in accordance with its terms.
3.3 No Legal Obstacle to Agreement. The execution, delivery and
performance of this Fourth Amendment will not (a) contravene the
terms of the Company's certificate of incorporation, by-laws or
other organization document; (b) conflict with or result in any
breach or contravention of the provisions of any contract to
which the Company is a party, or the violation of any law,
judgment, decree or governmental order, rule or regulation
applicable to Company, or result in the creation under any
agreement or instrument of any security interest, lien, charge,
or encumbrance upon any of the assets of the Company. No
approval or authorization of any governmental authority is
required to permit the execution, delivery or performance by the
Company of this Fourth Amendment, or the transactions
contemplated hereby.
3.4 Incorporation of Certain Representations. The representations
and warranties of the Company set forth in Section 5 of the
Agreement are true and correct in all respects on and as of the
date hereof as though made on and as of the date hereof.
3.5 Default. No Default or Event of Default under the Agreement has
occurred and is continuing.
4. Conditions, Effectiveness. The effectiveness of this Fourth Amendment
shall be subject to the compliance by the Company with its agreements
herein contained, and to the delivery of the following to the Agent in
form and substance satisfactory to the Agent and the Banks:
4.1 Resolutions and Authorized Signatories. Copies of the
resolutions of the board of directors of the Company approving
and authorizing the execution, delivery and performance by the
Company of this Fourth Amendment certified by the Secretary or
an Assistant Secretary of the Company, as of the date of this
Fourth Amendment, along with a certificate, signed by the
Secretary or an Assistant Secretary of the Company and dated the
date of this Fourth Amendment, as to the incumbency of the
person or persons authorized to execute and deliver this Fourth
Amendment and any instrument or agreement required hereunder on
behalf of the Company.
4.2 Other Evidence. Such other evidence with respect to the Company
or any other person as the Agent or any Bank may reasonably
request in connection with this Fourth Amendment and the
compliance with the conditions set forth herein.
5. Miscellaneous.
5.1 Purchasing and Selling of Commitments and Loans. On the date of
this Fourth Amendment, certain Banks (the "Buying Banks") hereby
agree to purchase without recourse, and certain Banks (the
"Selling Banks") hereby agree to sell without recourse, such an
interest in the Aggregate Commitment and the outstanding Loans
as is required (together with the increase in the Aggregate
Commitment provided for in Schedule 1.1) to give each Bank its
share of the Aggregate Commitment and Loans indicated on
Schedule 1.1 hereto.
Each Selling Bank represents and warrants to each Buying Bank
that it is the legal and beneficial owner of the Commitment and
Loans being assigned by it and that the same are free and clear
of any adverse claim. Other than as provided above, no Selling
Bank makes any representation or warranty and assumes no
responsibility with respect to the Commitments, the Loans, this
Agreement or any other instrument or document furnished pursuant
thereto, the financial condition of the Company, or the
performance or observance by the Company hereunder. The Company
agrees to pay on demand directly to any Selling Bank any costs
of the type set forth in Section 3.6 of the Agreement incurred
by such Selling Bank in respect of any portion of its Loans
being assigned hereunder. The Company and the Agent hereby
consent to such assignments.
60
<PAGE> 3
By signing below, each Buying Bank not heretofore a Bank
hereunder agrees to be a party to, and be bound by the terms of,
this Agreement as a "Bank" thereunder as if a signatory thereto.
From and after the date hereof, Boatmen's First National Bank of
Oklahoma and First Southwest Bank of Frederick shall no longer
be parties to this Agreement.
5.2 Effectiveness of the Agreement and the Loan Documents. Except as
hereby expressly amended, the Agreement and each other Loan
Document shall each remain in full force and effect, and are
hereby ratified and confirmed in all respects on and as of the
date hereof.
5.3 Waivers. This Fourth Amendment is limited solely to the matters
expressly set forth herein and is specific in time and in intent
and does not constitute, nor should it be construed as, a waiver
or amendment of any other term or condition, right, power or
privilege under the Agreement, the Loan Documents, or under any
agreement, contract, indenture, document or instrument mentioned
therein; nor does it preclude or prejudice any rights of the
Agent or the Banks thereunder, or any exercise thereof or the
exercise of any other right, power or privilege, nor shall it
require the Requisite Banks to agree to an amendment, waiver or
consent for a similar transaction or on a future occasion, nor
shall any future waiver of any right, power, privilege or
default hereunder, or under any agreement, contract, indenture,
document or instrument mentioned in the Agreement, constitute a
waiver of any other default of the same or of any other term or
provision.
5.4 Counterparts. This Fourth Amendment may be executed in any
number of counterparts and all of such counterparts taken
together shall be deemed to constitute one and the same
instrument. This Fourth Amendment shall not become effective
until the Company, the Banks and the Agent shall have signed a
copy hereof, whether the same or counterparts, and the same
shall have been delivered to the Agent.
5.5 Jurisdiction. This Fourth Amendment shall be governed by and
construed under the laws of the State of California.
IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be
duly executed and delivered as of the date first written above.
ONEOK INC.
By: JERRY D. NEAL
-------------------------------------------------------
Name: Jerry D. Neal
------------------------------------------------------
Title: Vice President, Chief Financial Officer and Treasurer
-----------------------------------------------------
BANK OF AMERICA NATIONAL TRUST AND
SAVINGS ASSOCIATION, as Agent
By: DAVID E. SISLER
-------------------------------------------------------
Name: David E. Sisler
------------------------------------------------------
Title: Vice President
-----------------------------------------------------
(Signatures continue)
61
<PAGE> 4
BANK OF AMERICA NATIONAL TRUST AND
SAVINGS ASSOCIATION, as a Bank
By: DAVID E. SISLER
-------------------------------------------------------
Name: David E. Sisler
------------------------------------------------------
Title: Vice President
-----------------------------------------------------
NATIONSBANK OF TEXAS, N.A.
By: CURTIS L. ANDERSON
-------------------------------------------------------
Name: Curtis L. Anderson
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
TEXAS COMMERCE BANK NATIONAL ASSOCIATION
By: DONNA J. GERMAN
-------------------------------------------------------
Name: Donna J. German
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
BANK OF OKLAHOMA NA
By: JANE P. FAULKENBERRY
-------------------------------------------------------
Name: Jane P. Faulkenberry
------------------------------------------------------
Title: Vice President
-----------------------------------------------------
MELLON BANK, N.A.
By: A. GARY CHACE
-------------------------------------------------------
Name: A. Gary Chace
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
PNC BANK, NATIONAL ASSOCIATION
By: BRIAN M. BEGG
-------------------------------------------------------
Name: Brian M. Begg
------------------------------------------------------
Title: Commercial Banking Officer
-----------------------------------------------------
(Signatures continue)
62
<PAGE> 5
SUNTRUST BANK, ATLANTA
By: TODD C. DAVIS
-------------------------------------------------------
Name: Todd C. Davis
------------------------------------------------------
Title: Assistant Vice President
-----------------------------------------------------
By: TRISHA E. HARDY
-------------------------------------------------------
Name: Trisha E. Hardy
------------------------------------------------------
Title: Corporate Banking Officer
-----------------------------------------------------
UMB BANK, N.A.
By: DAVID A. PROFFITT
-------------------------------------------------------
Name: David A. Proffitt
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
LIBERTY BANK AND TRUST COMPANY OF OKLAHOMA CITY, N.A.
By: MARK C. DEMOS
-------------------------------------------------------
Name: Mark C. Demos
------------------------------------------------------
Title: Vice President
-----------------------------------------------------
BANK ONE, OKLAHOMA CITY
By: JAMES R. KARCHER
-------------------------------------------------------
Name: James R. Karcher
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
LIBERTY BANK AND TRUST COMPANY OF TULSA, NATIONAL ASSOCIATION
By: CHRISTOPHER D. WILSON
-------------------------------------------------------
Name: Christopher D. Wilson
------------------------------------------------------
Title: Assistant Vice President
-----------------------------------------------------
(Signatures continue)
63
<PAGE> 6
WESTAR BANK OF BARTLESVILLE
By: CHARLES BAXTER
-------------------------------------------------------
Name: Charles Baxter
------------------------------------------------------
Title: Commercial Loan Officer
-----------------------------------------------------
AMERICAN NATIONAL BANK & TRUST COMPANY OF SHAWNEE
By: TONY M. MCMURRAY
-------------------------------------------------------
Name: Tony M. McMurray
------------------------------------------------------
Title: Executive Vice President
-----------------------------------------------------
CITIZENS BANK OF LAWTON
By: JOHN T. WOMACK
-------------------------------------------------------
Name: John T. Womack
------------------------------------------------------
Title: President
-----------------------------------------------------
THE STILLWATER NATIONAL BANK AND TRUST COMPANY
By: DAVID W. PITTS
-------------------------------------------------------
Name: David W. Pitts
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
NATIONSBANK, N.A. SUCCESSOR BY MERGER TO
BOATMEN'S FIRST NATIONAL BANK OF OKLAHOMA
(as a Selling Bank for purposes of Section 5.1 only)
By: CURTIS L. ANDERSON
-------------------------------------------------------
Name: Curtis L. Anderson
------------------------------------------------------
Title: Senior Vice President
-----------------------------------------------------
FIRST SOUTHWEST BANK OF FREDERICK
(as a Selling Bank for purposes of Section 5.1 only)
By: GREG BOUDREAU
-------------------------------------------------------
Name: Greg Boudreau
------------------------------------------------------
Title: Vice President
-----------------------------------------------------
64
<PAGE> 7
SCHEDULE 1.1
COMMITMENTS AND PRO RATA SHARES
<TABLE>
<CAPTION>
PRO RATA
BANK COMMITMENT SHARE
- --------------------------------------------------------------------------------
<S> <C> <C>
Bank of America National Trust
and Savings Association $ 35,000,000 20.0000000000%
NationsBank of Texas, N.A 25,000,000 14.2857142857
Texas Commerce Bank, National
Association 25,000,000 14.2857142857
Bank of Oklahoma NA 20,000,000 11.4285714289
Mellon Bank, N.A 15,000,000 8.5714285715
PNC Bank, National Association 10,000,000 5.7142857143
SunTrust Bank, Atlanta 10,000,000 5.7142857143
UMB Bank, N.A 10,000,000 5.7142857143
Liberty Bank and Trust Company
of Oklahoma City, N.A 8,000,000 4.5714285715
Bank One, Oklahoma City 6,000,000 3.4285714286
Liberty Bank and Trust Company of
Tulsa, National Association 6,000,000 3.4285714286
Westar Bank of Bartlesville 2,000,000 1.1428571429
American National Bank &
Trust Company of Shawnee 1,000,000 .5714285800
Citizens Bank of Lawton 1,000,000 .5714285800
The Stillwater National Bank
and Trust Company 1,000,000 .5714285800
- --------------------------------------------------------------------------------
TOTAL $175,000,000 100.0000000000%
</TABLE>
65
<PAGE> 8
SCHEDULE 3
OFFSHORE AND DOMESTIC LENDING OFFICES
ADDRESSES FOR NOTICES
David Sisler
Vice President
Bank of America NT&SA (Agent and Lender)
Three Allen Center, Ste. 4550
333 Clay Street
Houston, TX 77002
Phone: (713) 651-4875
Fax: (713) 651-4808
May Seeman
Bank of America NT&SA (Lending Office)
4th Floor
1850 Gateway
Concord, CA 94520
Phone: (510) 675-7483
Fax: (510) 603-8208
Curtis L. Anderson
NationsBank of Texas, N.A.
Sixty Fourth Floor
901 Main Street
Dallas, TX 75202
Phone: (214) 508-1290
Fax: (214) 508-3943
Donna German
Texas Commerce Bank National
Association
2200 Ross Avenue, 3rd Floor
Dallas, TX 75201
Phone: (214) 965-2540
Fax: (214) 965-2389
Jane A. Faulkenberry
Vice President
Bank of Oklahoma NA
Eighth Floor
One Williams Center
Tulsa, OK 74172
Phone: (918) 588-6272
Fax: (918) 588-6880
Gary Chace
Senior Vice President
Mellon Bank, N.A.
One Mellon Bank Center
Suite 4425
Pittsburgh, PA 15258-0001
Phone: (412) 236-2786
Fax: (412) 234-8888
66
<PAGE> 9
Christopher Moravec
PNC Bank, National Association
One PNC Plaza, 3rd Floor
249 Fifth Avenue
Pittsburgh,, PA 15222-2707
Phone: (412) 762-2540
Fax: (412) 762-2571
Todd C. Davis
SunTrust Bank, Atlanta
25 Park Place, MC 120
Atlanta, GA 30303
Phone: (404) 658-4917
Fax: (404) 827-6270
David A. Proffitt
Senior Vice President
UMB Bank, N.A.
Commercial Loan Dept.
1010 Grand Blvd.
Kansas City, MO 64106
Phone: (816) 860-7935
Fax: (816) 860-7143
Mark C. Demos
Liberty Bank and Trust Company
of Oklahoma City, N.A.
200 North Broadway
Oklahoma City, OK 73102
Phone: (405) 231-6974
Fax: (405) 231-6788
Jim Karcher
Bank One, Oklahoma City
6303 North Portland
Oklahoma City, OK 73112
Phone: (405) 272-2860
Fax: (405) 272-2844
William R. Hellen, Jr.
Liberty Bank and Trust Company
of Tulsa, National Association
Fourth Floor
15 East Fifth Street
Tulsa, OK 74103
Phone: (918) 586-5539
Fax: (918) 586-5952
Charles Baxter
WestStar Bank of Bartlesville
100 Southeast Frank Phillips Blvd.
Bartlesville, OK 74003
(P.O. Box 999
Bartlesville, OK 74005-0999)
Phone: (918) 337-3226
Fax: (918) 337-3506
67
<PAGE> 10
Tony McMurry
American National Bank &
Trust Company of Shawnee
201 North Broadway
Shawnee, OK 74801
Phone: (405) 273-5000
Fax: (405) 275-9240
Dan Torbett
Citizens Bank of Lawton
1420 W. Lee Boulevard
Lawton, OK 73505
Phone: (405) 250-4145
Fax: (405) 250-4343
David W. Pitts
The Stillwater National
Bank and Trust Company
608 South Main Street
Stillwater, OK 74076
Phone: (405) 372-2230
Fax: (405) 377-3808
68
<PAGE> 1
Exhibit (10)(q)
August 1, 1997
ONEOK Inc.
100 West Fifth Street
Tulsa, OK 74103-4298
Attn: Ms. Claudia T. Vandiver
General Manager
Financial Planning and Services
Gentlemen:
We are pleased to make available to you an uncommitted credit facility for
general corporate purposes on the terms set forth in this letter.
1. We agree to consider from time to time your requests that we make
advances to you, on a discount basis ("Advances"), in an aggregate
amount not to exceed at any one time outstanding the amount set forth on
Schedule I hereto as the "Facility Amount," on the terms and conditions
set forth below. This letter is not a commitment to lend, but rather
sets forth the procedures to be used in connection with your requests
for our making of Advances to you from time to time on or prior to the
termination hereof pursuant to paragraph 10 and, in the event that we
make Advances to you hereunder, your obligations to us with respect
thereto. The Advances shall be evidenced by the "grid" promissory note
executed by you in substantially the form of Exhibit A hereto (the
"Note").
2. The net amount of each Advance shall be in an amount at least equal to
the amount set forth on Schedule I hereto as the "Minimum Advance
Amount" and shall be made upon (i) your request to us by telephone,
telecopy or letter, given by any of the persons listed on Exhibit B
hereto or otherwise designated by you in writing ("Designated Persons"),
that you wish to borrow money on a specified date, in a specified amount
and for a specified term (which shall, in no event, be longer than the
number of days set forth on Schedule I hereto as the "Maximum Term");
and (ii) our mutual agreement as to such date, amount and term and as to
the discount applicable to any such Advance. On the date of any such
Advance, we will make such Advance available to you in same day funds by
directing our Administrative Agent (which is NationsBank, N.A. or its
successor) to transfer or wire the net proceeds of such Advance to an
account designated in writing by a Designated Person. Promptly after the
date of each Advance, our Administrative Agent will send you a written
confirmation of such Advance and the amount and term thereof and the
discount applicable thereto.
3. You shall deliver to us, certified by your Secretary or an Assistant
Secretary, resolutions of your Board of Directors authorizing the
execution and delivery of this letter and any and all documents
delivered pursuant hereto, together with a certificate of incumbency
(with specimen signatures).
The delivery of the foregoing, together with this executed letter and
any and all documents delivered pursuant hereto, shall constitute a
representation and warranty by you that (a) the execution, delivery and
performance of this letter has been duly authorized by all necessary
corporate action and does not contravene any law, or any contractual or
legal restriction, applicable to you, and (b) no authorization or
approval or other action by, and no notice to or filing with, any
governmental authority or regulatory body is required for such
execution, delivery and performance.
4. Each request by you for an Advance shall constitute a representation and
warranty by you, as of the making of such Advance and giving effect to
the application of the proceeds therefrom, that (i) no payment default
has occurred and is continuing under any agreement or instrument
relating to any of your indebtedness, (ii) such Advance when made will
constitute your legal, valid and binding obligation, (iii) such Advance
is being incurred, and will be repaid at maturity, in the ordinary
course of your business out of the cash flow generated in the normal
day-to-day conduct and operations of your business, and (iv) no event
has occurred and no circumstance exists as a result of which the
information which you have provided to us in connection herewith would
include an untrue statement of a material fact or omit to state any
material fact or any fact necessary to make the statements contained
herein, in the light of the circumstances under which they were made,
not mis-leading.
69
<PAGE> 2
5. You shall repay each Advance in accordance with the terms hereof and of
the Note. You shall have no right to prepay any unpaid principal amount
of any Advance.
6. You shall make each payment hereunder and under the Notes on or before
12:00 noon (New York City time) on the day when due in lawful money of
the United States of America to us in same day funds at Bankers Trust
Company; ABA #021001033; Corporate Trust Agency Group Account #01419647;
Reference: Ranger Funding.
7. Whenever any payment to be made hereunder shall be otherwise due on a
Saturday, a Sunday or other day of the year on which banks are required
or authorized to close in New York (any other day being a "Business
Day"), such payment shall be made on the next succeeding Business Day.
8. You agree that you will not apply the proceeds of any Advance to
purchase or carry margin stock within the meaning of Regulation G issued
by the Board of Governors of the Federal Reserve System.
9. We shall incur no liability to you in acting upon any telephone,
telecopy, telex or letter request or communication which we believe in
good faith to have been given by a Designated Person or in otherwise
acting in good faith under this letter. Further, all documents required
to be executed in conjunction with Advances under this letter may be
signed by any Designated Person.
10. This letter shall remain in effect until terminated by either you or us
by giving prior written notice of termination hereof to the other party
hereto, but no such termination shall affect your obligations with
respect to the Advances hereunder outstanding at the time of such
termination.
11. All written communications hereunder shall be mailed, telecopied or
delivered to the address specified on Schedule I hereto for you and for
us, or as to each party, to such other address as may be designated by
such party in a written notice to the other party. Written communication
shall be effective upon receipt unless such communication is mailed in
which case it shall be effective three Business Days after deposit in
first class mail.
12. We may assign to one or more banks or other entities all or any part of,
or may grant participations to one or more banks or other entities in or
to all or any part of, any Advance or Advances hereunder and under the
Note. You may not assign your rights or obligations hereunder or any
interest herein without our prior written consent and the written
confirmation from each of Standard & Poor's Corporation and Moody's
Investors Service, Inc. that as a result of such assignment the then
current rating of the commercial paper issued by Ranger Funding
Corporation will not be downgraded or withdrawn and any such assignment
without our consent shall be null and void.
13. You agree to pay on demand all reasonable costs, expenses and losses, if
any, incurred by us in connection with the enforcement of this letter or
the Note.
14. You agree to furnish us with such financial statements or other
information as we may reasonably request.
15. If any of the following events shall occur and be continuing:
(a) you shall fail to pay any amount due hereunder or under the Note
when the same becomes due and payable; or
(b) any representation or warranty made by you (or any of your officers)
in connection with any Advance or otherwise in connection with the Note
shall prove to have been incorrect in any material respect when made; or
70
<PAGE> 3
(c) you shall, without our prior written consent, merge or consolidate
with or into, or convey, transfer, lease or dispose of (whether in one
transaction or in a series of transactions) all or substantially all of
your assets to, any person or entity; or
(d) you shall fail to perform or observe any other material term,
covenant or agreement in connection with any Advance or otherwise in
connection with the Note on your part to be performed or observed; or
(e) you shall fail to pay any principal of or premium or interest on any
indebtedness, which we deem to be material, (excluding indebtedness
evidenced by the Note), when the same becomes due and payable (whether
by scheduled maturity, required prepayment, acceleration, demand or
otherwise), and such failure shall continue after the applicable grace
period, if any, specified in the agreement or instrument relating to
such indebtedness; or any other event shall occur or condition shall
exist under any agreement or instrument relating to such indebtedness
and shall continue after the applicable grace period, if any, specified
in such agreement or instrument, if the effect of such event or
condition is to accelerate, or to permit the acceleration of, the
maturity of such indebtedness; or any such indebtedness shall be
declared to be due and payable, or required to be prepaid (other than by
a regularly scheduled required prepayment), prior to the stated maturity
thereof; or
(f) you shall generally not pay your debts as such debts become due, or
shall admit in writing your inability to pay your debts generally, or
shall make a general assignment for the benefit of creditors; or any
proceeding shall be instituted by or against you seeking to adjudicate
you as bankrupt or insolvent, or seeking liquidation, winding up,
reorganization, arrangement, adjustment, protection, relief, or
composition of you or your debts under any law relating to bankruptcy,
insolvency or reorganization or relief of debtors, or seeking the entry
of an order for relief or the appointment of a receiver, trustee,
custodian or other similar official for you or any substantial part of
your property; or you shall take any corporate action to authorize any
of the actions set forth above in this subsection (f); then, and in any
such event, we may declare the Note, and all amounts payable thereunder
to be forthwith due and payable, whereupon the Note, and all such
amounts shall become and be forthwith due and payable, without
presentment, demand, protest or further notice of any kind all of which
you hereby expressly waive; provided, however, that in the event of an
actual or deemed entry of an order for relief with respect to you under
the Federal Bankruptcy Code, the Note, and all such other amounts shall
automatically become and be due and payable, without presentment,
demand, protest or any notice of any kind, all of which are hereby
expressly waived by you.
16. THIS LETTER SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE
LAWS OF THE STATE OF NEW YORK.
17. You and we each hereby irrevocably waive all right to trial by jury in
any action, proceeding or counterclaim (whether based upon contract,
tort or otherwise) arising out of or relating to this letter or the
Note.
18. You agree that you will not institute against or join any other person
in instituting against us any bankruptcy, reorganization, arrangement,
insolvency or liquidation proceeding, or other proceeding under any
federal or state bankruptcy or similar law, for one year and a day after
the latest maturing Commercial Paper issued by us is paid in full.
19. At our option, we shall, upon notice that either Standard & Poor's
Corporation or Moody's Investors Service, Inc. has (i) lowered or
downgraded its short term commercial paper or corporate bond or other
short term rating of you, (ii) placed your securities on a watch list of
securities singled out for surveillance, with either negative or
developing implications, or (iii) withdrawn its approval of you for
inclusion in a Ratings Category, amend Schedule I hereof to provide for
an amended "Facility Amount" and amended "Maximum Term."
71
<PAGE> 4
20. As long as you shall have any Advances outstanding, you agree that you
will maintain a separate line of credit with a commercial bank, in an
unutilized aggregate amount equal to the amount of all outstanding
Advances.
21. The obligations of Ranger Funding Corporation under this Agreement are
solely the corporate obligations of Ranger Funding Corporation. No
recourse shall be had for the payment of any amount owing hereunder or
any other obligation or claim of or against Ranger Funding Corporation
arising out of or based upon this Agreement against any stockholder,
employee, officer, director or incorporator of the Ranger Funding
Corporation, or against the Administrative Agent or any stockholder,
employee, officer, director, incorporator or Affiliate thereof.
If the terms of this letter are satisfactory to you, please indicate your
agreement and acceptance thereof by signing a counterpart of this letter and
returning it to us.
Very truly yours,
RANGER FUNDING CORPORATION
By: RICHARD L. TAIANO
------------------------------
Name: Richard L. Taiano
Title: Vice President
Agreed and Accepted:
ONEOK INC.
By: JERRY D. NEAL
-----------------------------------------------------
Name: Jerry D. Neal
Title: Vice President - Chief Financial Officer
72
<PAGE> 5
Schedule I to The Loan Agreement
dated as of August 1, 1997
Between Ranger Funding Corporation and ONEOK Inc.
(i) For the purpose of Sections 1 and 2 of this Loan Agreement:
The "Facility Amount" is $25,000,000.00
The "Minimum Advance Amount" is $5,000,000.00
The "Maximum Term" is 70 days
(ii) For the purpose of Section 11 of this Loan Agreement:
The address for written communications to Borrower is:
100 West Fifth Street
Tulsa, OK 74103-4298
Attention: Ms. Claudia T. Vandiver
General Manager, Financial Planning and Services
Telephone: (918) 588-7162
Fax: (918) 588-7114
The address for written communications to us is:
Ranger Funding Corporation
c/o NationsBank, N.A.
Attention: Camille Zerbinos
100 North Tryon Street, NC1-007-10-06
Charlotte, NC 28255
Telephone: (704) 388-2100
Fax: (704) 388-9211
(iii) For purposes of this Loan Agreement, instructions for wire transfer of
funds to the Borrower are:
Name of Bank: Boatmen's N.A.
Oklahoma
Bank ABA Number: 103000017
Borrower Number: 039024520599
Reference: ONEOK Inc.
Ranger Funding
73
<PAGE> 6
EXHIBIT A
to
The Loan Agreement
SHORT-TERM PROMISSORY GRID NOTE
$25,000,000.00 Dated August 1, 1997
FOR VALUE RECEIVED, the undersigned (the "Borrower"), HEREBY PROMISES TO PAY to
the order of Ranger Funding Corporation (the "Lender") with respect to each
Advance (as defined below) the face amount of such Advance, on the date mutually
agreed to by the Lender and the Borrower at the time of such Advance as the
maturity date thereof.
Any overdue principal amount, fees or other amounts payable hereunder or under
the Loan Agreement referred to below shall bear interest, payable on demand, at
a fluctuating interest rate per annum equal at all times to NationsBank, N.A.
base rate plus 2%.
The Borrower shall have no right to prepay any unpaid principal amount of any
Advance.
The Borrower shall make each payment hereunder prior to 12:00 noon (New York
City time) on the day when due in lawful money of the United States of America
to Bankers Trust Company; ABA #021001033; Corporate Trust Agency Group Account
#01419647; Reference: Ranger Funding. Whenever any payment to be made hereunder
shall be otherwise due on a Saturday, a Sunday or a public or bank holiday in
New York (any other day being a "Business Day"), such payment shall be made on
the next succeeding Business Day.
The Borrower hereby authorizes the Lender to endorse on the grid attached hereto
the date and amount of each Advance made by the Lender to the Borrower
hereunder, the maturity date thereof, all payments made on account of principal
thereof, provided, that the failure to do so shall not affect the obligations of
the Borrower to the Lender.
The Borrower also agrees to pay on demand all reasonable costs and expenses
(including fees and expenses of counsel) incurred by the Lender in enforcing
this Promissory Note.
THIS PROMISSORY NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE
LAWS OF THE STATE OF NEW YORK.
The Borrower and the Lender hereby irrevocably waive all right to trial by jury
in any action, proceeding or counterclaim (whether based upon contract, tort or
otherwise) arising out of or relating to this Promissory Note or any Advances
hereunder.
This Promissory Note is the "grid" promissory note referred to in, and is
entitled to the benefits of the Loan Agreement dated August 1, 1997 (the "Loan
Agreement"), between the Borrower and the Lender, which Loan Agreement, among
other things, sets forth procedures to be used in connection with the Borrower's
periodic requests that the Lender make advances (the "Advances") to it from time
to time in an aggregate amount not to exceed at any time outstanding the amount
first above mentioned.
ONEOK INC.
By: JERRY D. NEAL
------------------------------------------------
Name: Jerry D. Neal
Title: Vice President - Chief Financial Officer
74
<PAGE> 7
EXHIBIT B
to
The Loan Agreement
For the purpose of Sections 2 and 9 of this Loan Agreement, the "Designated
Persons" are:
Name: Jerry D. Neal
--------------------------------------------------------
Title: Vice President - Chief Financial Officer
--------------------------------------------------------
Specimen Signature: JERRY D. NEAL
--------------------------------------------------------
Name: Claudia Vandiver
--------------------------------------------------------
Title: General Manager - Financial Planning and Services
--------------------------------------------------------
Specimen Signature: CLAUDIA VANDIVER
--------------------------------------------------------
Name: Dennis J. Inman
--------------------------------------------------------
Title: Financial Accounting Specialist
--------------------------------------------------------
Specimen Signature: DENNIS J. INMAN
--------------------------------------------------------
Name:
--------------------------------------------------------
Title:
--------------------------------------------------------
Specimen Signature:
--------------------------------------------------------
Name:
--------------------------------------------------------
Title:
--------------------------------------------------------
Specimen Signature:
--------------------------------------------------------
Name:
--------------------------------------------------------
Title:
--------------------------------------------------------
Specimen Signature:
--------------------------------------------------------
75
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENT OF INCOME FOR THE FISCAL YEAR ENDED AUGUST 31, 1997, AND
THE CONSOLIDATED BALANCE SHEET AT AUGUST 31, 1997, FOR ONEOK INC. AND
SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1997
<PERIOD-START> SEP-01-1997
<PERIOD-END> AUG-31-1997
<CASH> 14,377
<SECURITIES> 0
<RECEIVABLES> 100,937
<ALLOWANCES> 0
<INVENTORY> 4,303
<CURRENT-ASSETS> 207,272
<PP&E> 1,429,493
<DEPRECIATION> 586,156
<TOTAL-ASSETS> 1,237,407
<CURRENT-LIABILITIES> 189,691
<BONDS> 0
0
0
<COMMON> 229,803
<OTHER-SE> 232,823
<TOTAL-LIABILITY-AND-EQUITY> 1,237,407
<SALES> 0
<TOTAL-REVENUES> 1,161,927
<CGS> 0
<TOTAL-COSTS> 1,067,974
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 34,685
<INCOME-PRETAX> 94,107
<INCOME-TAX> 34,839
<INCOME-CONTINUING> 59,268
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 59,268
<EPS-PRIMARY> 2.13
<EPS-DILUTED> 2.13
</TABLE>
