<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(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, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from ______ to ______
Commission file number 1-2572
ONEOK INC.
(Exact name of registrant as specified in its charter)
DELAWARE 73-0383100
(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
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
Common stock, without par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
- -------------------
Preferred stock, $50 par value, Series A, 4 3/4% cumulative
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K/A or any amendment to
this Form 10-K/A.
---
Aggregate market value of registrant's voting stock held by nonaffiliates as of
October 1, 1996, was: Common stock $748.2 million; Preferred stock $5.4
million.
On October 1, 1996, the Company had 27,268,301 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
DOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement dated November 7, 1996. Part III
<PAGE> 2
ONEOK INC.
1996 ANNUAL REPORT ON FORM 10-K/A
<TABLE>
<S> <C>
PART I PAGE NO.
Item 1. Business 3-9
Item 2. Properties 9-11
Item 3. Legal Proceedings 12-13
Item 4. Results of Votes of Security Holders 14
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 17-25
Item 8. Financial Statements and Supplementary Data 26-46
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 47
PART III
Item 10. Directors, Executive Officers, Promoters, and
Control Persons of the Registrant 47
Item 11. Executive Compensation 47
Item 12. Security Ownership of Certain Beneficial Owners
and Management 47
Item 13. Certain Relationships and Related Transactions 47
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 48-64
</TABLE>
2
<PAGE> 3
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 1981.
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 three subsidiaries, ONG
Gathering Company, 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 and ONEOK
Exploration Company. Other businesses include ONEOK Leasing Company; ONEOK
Parking Company; and Fifth Street Investment Corporation.
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 1996 fiscal year related to
compliance with these regulations. No material effects of this nature are
anticipated during the 1997 fiscal year.
EMPLOYEES - The Company employed 1,884 persons at August 31, 1996, and is
currently not a party to any collective bargaining agreements with such
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 three 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
3
<PAGE> 4
Natural Gas Company, ONG Transmission Company, ONG Sayre Storage Company
(Sayre), and ONG Gas Gathering Company are consolidated for ratemaking
purposes by the Oklahoma Corporation Commission (OCC).
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
729,500 customers at August 31, 1996, located in 294 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 44
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 44.0, 62.3, and 78.6 percent for
1996, 1995, and 1994, respectively. Operating income before interest and
taxes from the regulated operations is 80.4, 86.8, and 95.4 percent of the
consolidated operating income before interest and taxes for 1996, 1995,
and 1994, respectively.
The Company is interested in acquiring gas distribution and transmission
facilities which will enhance its operations and continues to pursue
opportunities for acquisitions as they occur.
GAS SUPPLY
Gas supplies available to Oklahoma Natural Gas for purchase and resale or
transportation 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 25 interconnect points,
38 gas processing plants and 129 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 A new record for all-time peak gas
deliveries through the system in a single day of 1.92 billion cubic feet
was set on February 2, 1996.
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 56 and 29 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.
4
<PAGE> 5
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 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 42 other
municipalities in which there is an aggregate population of approximately
102,000. 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 gas delivered through the
pipeline system is delivered to industrial customers, in particular,
several large fertilizer plants which use the gas as feed stock. In the
past, certain interstate and intrastate pipeline companies have been 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 (SISP) Programs. 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". Currently, all the fertilizer plants are operating at or
near full capacity. 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 23.
COMPETITION
The natural gas industry is expected to remain highly competitive with
respect to both gas supply and markets. 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. Strategic planning has identified several potential new
service opportunities. Such services could include equipment service
contracts, operating services, gas marketing and supply management, gas
storage for others, gas measurement services and gas transportation.
Oklahoma Natural Gas is subject to competition from electric utilities,
offering electricity as a rival energy source, 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 home heating, natural gas service provided by
Oklahoma Natural Gas is 57 percent, 53 percent and 71 percent less
expensive. Oklahoma Natural Gas rates are competitive nationally. In
residential markets, the average cost of 10 Mcf is $51.41 for Oklahoma
Natural Gas customers versus $58.01 for the average cost in 31 cities
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 new PCL
5
<PAGE> 6
rate structure approved in June 1995 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
its operations.
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.
In the past, the Company experienced claims and potential liabilities
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. There are no significant
potential claims or cases pending against the Company under remaining gas
purchase contracts. In a 1994 rate order, the OCC authorized an annual
recovery of $6.7 million of the accumulated settlement costs by a
combination of a surcharge from customers and revenue from transportation
under Section 311(a) of the NGPA and other intrastate transportation
revenues.
On June 19, 1995, the OCC approved a settlement of all issues in a pending
rate proceeding. Under the settlement, 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. The order also included a temperature adjustment clause, an
agreement not to file for a general rate increase for two years, and
amortization of the additional deferred pension costs not covered by prior
orders.
OTHER REGULATED BUSINESSES
Through its subsidiary, TransTex Pipeline Company (TransTex), the Company
owned a 25 percent limited partnership interest in Red River Pipeline (Red
River). Effective January 1, 1996, TransTex withdrew as a limited partner
and received as a distribution a portion of the assets of the partnership.
Such assets, which are regulated by the Railroad Commission of Texas, were
then leased back to Red River under a long term lease.
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. Although
formed in 1992, marketing did not have significant operations until 1995.
Due to expanded supply and storage capabilities the marketing operation
grew from an intrastate aggregator into a interstate aggregator with an
average daily sales volume of 868,401 MMbtu, 705,406 MMbtu, and 475,853
MMbtu in 1996, 1995, and 1994, respectively.
6
<PAGE> 7
Of the Company's consolidated operating revenues, revenue from the gas
marketing business represented approximately 48.9, 27.9, and 10.0 percent
for 1996, 1995, and 1994, respectively. Operating income before interest
and taxes from the marketing operation is 10.7, 4.5 and 4.1 percent of the
consolidated operating income before interest and taxes for 1996, 1995,
and 1994, respectively.
MARKET CONDITIONS - The marketing business is very competitive and, as the
industry matures, continues to go through a period of consolidation and
reduced margins. Management expects that mega-marketers (entities which
market over 5 Bcf per day) will dominate the industry. The Company's
strategy is to concentrate on margins and not compete on the basis of
volumes. 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 - Gas marketing is a low margin business that
experiences extreme volatility and can be expensive for small producers to
manage. Management believes that there are a significant number of such
producers in Oklahoma. Accordingly, the Company will introduce ONEOK
Producer Services, an entity which will specialize in servicing this niche
market. ONEOK Producer Services will focus on aggregating and providing
producer services under medium-term agreements. Service will be packaged
to meet each producer's needs, such as investigating options for new well
pipeline connections, facilitating connections, keeping production
balanced to nominated volumes and handling certain administrative
accounting functions.
The Company has filed an application with FERC to market electricity.
Management anticipates that permits will be granted during the first
quarter of 1997. It is not anticipated that such activities will be a
major contributor to earnings in 1997.
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. Currently, 12 plants are in operation and 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,
butane, propane, isobutane). Such liquids are used as a petrochemical
feedstock, for residential heating and cooking in rural areas, and blended
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 gas stream, thereby
reducing the Btu content and volume of incoming gas (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, 1996, the Company's processing plants are
operating with 70 percent "fuel and shrink" and 30 percent "percent of
proceeds" contracts.
7
<PAGE> 8
Of the Company's consolidated operating revenues, revenue from the gas
processing business represented approximately 4.8, 6.8, and 8.3 percent
for 1996, 1995, and 1994, respectively. Operating income before interest
and taxes for the processing operation is 7.4, 6.0, and 3.7 percent of the
consolidated operating income before interest and taxes for 1996, 1995,
and 1994, respectively.
PROCESSING CAPABILITIES - Recent developments include the expansion of
plant gathering systems into new areas of production, the development of
producer alliances and bringing plants 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.
Because of the generally favorable location of the plants and terms of the
Company's processing and operating agreements, management anticipates
continuing to have favorable fuel costs and anticipates that its currently
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 Oklahoma in order to add value not
only to its existing production operations but also to integrate the
processing, marketing, transmission and storage businesses. As a result,
the Company intends to focus its efforts on exploitation activities.
Effective September 1, 1996, the Company merged ONEOK Exploration Company
into ONEOK Resources Company.
Of the Company's consolidated operating revenues, revenue from the
production business represented approximately 2.1, 2.5, and 2.9 percent
for 1996, 1995, and 1994, respectively. Operating income before interest
and taxes for the production operation is 2.3, 3.4, and 0.8 percent of the
consolidated operating income before interest and taxes for 1996, 1995,
and 1994, respectively.
PRODUCING RESERVES - Natural gas is the primary focus of the Company's
production activities. As of August 31, 1996, the Company had working
interests in 821 gas wells and 237 oil wells located primarily in Oklahoma
and Louisiana. The Company acts as operator on 234 of these properties. A
number of these wells are multiple completions.
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 economical
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. The Company has expanded its hedging of gas
production using swaps and futures contracts.
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. The downtown Tulsa office leasing market continues
to have excess capacity. Rates remain relatively flat while the excess
capacity is being absorbed by the market.
8
<PAGE> 9
On August 18, 1995, the Company, through a subsidiary, Fifth Street
Investment Corporation, submitted a written offer to Midtown Associates,
the general partner of Southwestern Associates (the "Partnership"), the
owner of the office building, to acquire the Partnership's equity in the
building, subject to existing indebtedness. The offer was rejected. On
October 7, 1995, offers were made to purchase the interests of limited
partners in the Partnership at a price of $102,000 per unit for up to 33
aggregate units. In addition, an offer was made to the limited partners
guaranteeing at least $92,000 per unit when the building sells or the
Partnership dissolves in return for proxies to vote the interests of the
limited partners in the Partnership. The proxy offer was open to holders
of the first 45 aggregate units (including up to 33 aggregate units for
which the offers to purchase are accepted). The Company failed to receive
a sufficient amount of acceptances and withdrew its offer.
ITEM 2. PROPERTIES
(A) DESCRIPTION OF PROPERTY
REGULATED
DISTRIBUTION - Oklahoma Natural Gas owned 14,680 miles of pipeline and
other distribution facilities in Oklahoma at August 31, 1996. Oklahoma
Natural Gas 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.
Oklahoma Natural Gas Company also owns a fleet of vehicles and maintains
an inventory of spare parts, equipment, and supplies. In addition,
Oklahoma Natural Gas owns five underground storage facilities located
throughout the state. 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 storage capacity of 124.5 billion
cubic feet. The other storage facility is located in western Oklahoma and
is leased to and operated by another company. However, 21.5 billion cubic
feet of storage capacity in this facility have been retained for use by
Oklahoma Natural Gas.
TRANSMISSION - Oklahoma Natural Gas owned a combined total of 3,840 miles
of transmission and gathering pipeline in Oklahoma at August 31, 1996.
Compression and dehydration facilities are located at various points
throughout the pipeline system.
Through a subsidiary, the Company leases 57.89 miles of transmission
pipeline in Texas to the Red River Pipeline.
PRODUCTION
The Company owns varying economic interests, including overriding royalty
interests, in 821 gas wells and 237 oil wells, some of which are multiple
completions. Such interests are in wells located primarily in Louisiana
and Oklahoma. The Company owns 73,227 net onshore developed leasehold
acres and 14,014 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 which extract
liquid hydrocarbons from natural gas. All are located in Oklahoma. The
Company's share of the capacity of the plants totals 334 million cubic
feet per day.
9
<PAGE> 10
OTHER
The Company owns a parking garage with 1,179 parking spaces 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 260,000 square
feet of space for its own use and leases the remaining space to others.
(B) OTHER INFORMATION
Production figures are defined by the Securities and Exchange Commission
(SEC) to include natural gas liquids from Company-owned leases. The
Company 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 leases producing the gas processed by
these plants. As a result of this exclusion by the SEC, information
concerning these natural gas liquids is not included in any of the tables
in this section.
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 44.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES - See Note M of Notes to
Consolidated Financial Statements on page 44 and 45.
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:
---------------------------------------------------------------------------
SALES 1996 1995 1994
---------------------------------------------------------------------------
Oil (MBbls) 435 466 515
Gas (MMcf) 9,406 8,775 8,043
---------------------------------------------------------------------------
AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS
Average sales prices and lifting costs are as follows:
---------------------------------------------------------------------------
1996 1995 1994
---------------------------------------------------------------------------
Average Sales Price (a)
Per Bbl of oil $ 17.73 $ 16.28 $ 14.81
Per Mcf of gas $ 1.86 $ 1.51 $ 1.99
Average Production Costs
Per Mcfe (b) $ 0.46 $ 0.37 $ 0.45
===========================================================================
(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.
10
<PAGE> 11
WELLS AND DEVELOPED ACREAGE
The table below shows gross and net wells in which the Company has a
working interest at August 31, 1996, and does not include wells in which
the Company has royalty or overriding royalty interests.
---------------------------------------------------------------------------
Oil Gas
---------------------------------------------------------------------------
Gross wells 219 693
Net wells 79 210
---------------------------------------------------------------------------
Gross developed acres and net developed acres by well classification are
not available. Net developed acres for both oil and gas is 73,227 acres.
UNDEVELOPED ACREAGE
The gross and net undeveloped leasehold acreage at the end of the fiscal
year was as follows:
---------------------------------------------------------------------------
GROSS NET
---------------------------------------------------------------------------
Alabama 548 82
Colorado 80 1
Louisiana 1,110 210
Oklahoma 48,797 11,906
Texas 13,891 1,815
---------------------------------------------------------------------------
Total 64,426 14,014
---------------------------------------------------------------------------
Of the net onshore undeveloped acres, approximately nine percent lies in
the Ardmore Basin area, 34 percent in the Anadarko Basin area in Oklahoma,
43 percent in the Oklahoma portion of the Arkoma Basin, and 14 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:
---------------------------------------------------------------------------
EXPLORATORY DEVELOPMENT
---------------------------------------------------------------------------
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
===========================================================================
1994
Productive 0.9 5.6
Dry 3.5 1.9
Total 4.4 7.5
===========================================================================
PRESENT DRILLING ACTIVITIES
On August 31, 1996, the Company was participating in the drilling of seven
wells. The Company's net interest in these wells amounts to 1.2 wells.
FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS
None
11
<PAGE> 12
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 yard line and for repairing the gap in piping caused by the
relocation of the meter to the property line and as a class action for
similarly situated customers. The company moved to dismiss the action on the
grounds the District Court did not have subject matter jurisdiction and a
failure to state a cause of action for which relief could be granted. The
District Court granted the motion to dismiss and the Plaintiffs appealed the
decision. On August 14, 1991, the Court of Appeals reversed the trial court's
decision and remanded the case for further proceedings. The appellate court
held that the trial court had erred in ruling both that it was without
jurisdiction and that the Plaintiffs had failed to state a cause of action,
instead finding that under Commission Rule 6(a) the Company could be
responsible for maintenance of the gas line up to the outflow side of the
meter. As a result, the Company could have a duty to repair the gap caused by
removal of the meter and to maintain and repair the yard line. The case was
remanded to the District Court, the Company filed a related proceeding with the
Oklahoma Corporation Commission seeking an interpretation of the applicable
Commission rules, and although the Plaintiffs filed a motion in district court
to certify the class, further proceedings in the case were stayed pending
resolution of the appeal of the decision in the related Corporation Commission
proceeding. The Corporation Commission 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 has appealed the ruling to the Oklahoma Supreme Court.
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. 95000223, 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.2d 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.
12
<PAGE> 13
UNITED STATES EX REL. JACK J. GRYNBERG V. ALASKA PIPELINE COMPANY, ET AL.
(INCLUDING ONEOK INC.), No. 95-725-TFH, in the United States District Court for
the District of Columbia. This is a qui tam action brought by the plaintiff on
behalf of the United States pursuant to the False Claims Act, 31 U.S.C. Section
3729, et seq., to recover the underpayment of royalties on federally owned or
Indian properties from 70 named pipeline companies, including ONEOK Inc. The
plaintiff claims that the 70 named pipeline companies have underpaid royalties
to the United States as a result of the improper measurement of the heating
content and volume of natural gas which they purchased from the federally owned
or Indian lands. On behalf of the United States, the plaintiff seeks to recover
the proceeds for the underpayment of royalties, interest, treble damages, civil
penalties of $5,000 to $10,000 for each violation by a defendant pipeline
company of the False Claims Act, and an order requiring the defendant pipeline
companies to discontinue the improper practices. The plaintiff also seeks to
recover his expenses incurred in bringing the action, plus attorneys' fees and
costs. All answers and responses to the Second Amended Complaint are due by
November 13, 1996.
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.
The investigation has been completed and a report on the results is currently
being compiled by the Staff.
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, or financial position, or liquidity.
13
<PAGE> 14
ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS
(A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS
None
(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 46 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
1991 to 1993 Executive Vice President of Oklahoma
Natural Gas Company (ONG)
- ---------------------------------------------------------------------------------------------
DAVID L. KYLE 44 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 1991 to 1994 Executive Vice President of
Company Oklahoma Natural Gas Company
- ---------------------------------------------------------------------------------------------
JERRY D. NEAL 57 1992 to present Vice-President, Treasurer, Chief
Vice-President, Treasurer, Financial Officer, and Chief
Chief Financial Officer, and Accounting Officer
Chief Accounting Officer
1991 to 1992 Vice-President of Finance
- ---------------------------------------------------------------------------------------------
NORMAN E. DUCKWORTH 62 1996 Vice-President and Secretary
Vice-President and Secretary 1991 to 1996 Vice-President of Human Resources
- ---------------------------------------------------------------------------------------------
EUGENE N. DUBAY 48 1996 Vice-President of Corporate Development
Vice-President of 1991 to 1995 Executive Vice-President and
Corporate Development Chief Operating Officer of Missouri Gas
Energy
- ---------------------------------------------------------------------------------------------
</TABLE>
14
<PAGE> 15
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>
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
<CAPTION>
1995 HIGH LOW
<S> <C> <C>
First quarter $18 $15 7/8
Second quarter $18 3/8 $16 7/8
Third quarter $19 5/8 $17 1/4
Fourth quarter $23 7/8 $18 3/4
</TABLE>
(B) HOLDERS
There were 13,267 holders of the Company's common stock at August 31,
1996.
(C) DIVIDENDS
Quarterly dividends declared on the Company's common stock during the last
two fiscal years were as follows:
---------------------------------------------------------------------------
1996 1995
---------------------------------------------------------------------------
First quarter $ .29 $ .28
Second quarter .29 .28
Third quarter .30 .28
Fourth quarter .30 .28
---------------------------------------------------------------------------
Total $ 1.18 $ 1.12
===========================================================================
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, 1996, $192,437,000 was available for dividends on the Company's common
stock.
15
<PAGE> 16
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>
- -----------------------------------------------------------------------------------------
1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $1,224.3 $ 954.2 $ 784.1 $ 789.1 $ 677.1
Operating income before interest
and income taxes $ 121.0 $ 105.5 $ 92.0 $ 96.5 $ 83.9
Net income $ 52.8 $ 42.8 $ 36.2 $ 38.4 $ 32.6
Total assets $1,219.9 $1,181.2 $1,148.1 $1,115.1 $1,069.9
Long-term debt $ 351.9 $ 363.9 $ 376.9 $ 391.9 $ 397.9
Earnings per common share $ 1.93 $ 1.58 $ 1.34 $ 1.43 $ 1.21
Dividends per common share $ 1.18 $ 1.12 $ 1.11 $ 1.06 $ .96
Percent of payout 61.1% 70.9% 82.8% 74.1% 79.3%
Common equity per share $ 15.21 $ 14.38 $ 13.88 $ 13.63 $ 13.28
Return on common equity 12.64% 10.90% 9.65% 10.46% 9.09%
Ratio of earnings to
fixed charges 3.44 2.56 2.39 2.33 2.21
- -----------------------------------------------------------------------------------------
</TABLE>
16
<PAGE> 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OPERATING ENVIRONMENT AND OUTLOOK
Each of the Company's business units has taken steps over the past two years to
strengthen its competitive edge and position it to be a leader in the industry.
The highlights for these units include:
o REGULATED OPERATIONS - 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.
o NONREGULATED OPERATIONS - ONEOK Gas Marketing experienced significant
growth in the last year becoming a billion cubic foot per day marketing
operation. The processing segment owns seven percent of the state's
processing capacity. Gathering systems around six plants were expanded to
bring them to operating capacity during the current year. The production
segment has significantly reduced its exploration activities; rather it
concentrates on exploitation activities and reserve ownership in Oklahoma.
Currently, 89 percent of the Company's reserves are located in Oklahoma,
up from 53 percent one year ago.
In the opinion of management, a significant indicator of future changes to be
encountered by the Company came in the form of a notice of inquiry (NOI)
regarding the restructuring of Oklahoma's gas utility industry issued by the
OCC in the spring of 1996. The Company supports restructuring and unbundling
the transmission, gathering, storage, customer service and gas supply
functions. Unbundling should enhance customer choices, service and value and
potentially should decrease unit costs, increase throughput, allow broader use
of the Company's assets, and strengthen economic development.
The Company plans to launch two new ventures to enhance its marketing group.
ONEOK Producer Services will bring gas marketing and other services to the
small gas producer to fill a niche market. In addition, the Company has filed
an application with FERC to market electricity.
CONSOLIDATED OPERATIONS
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
FINANCIAL RESULTS
Operating revenues - regulated $ 538,169 $ 594,923 $ 616,090
Operating revenue - nonregulated $ 686,176 $ 359,272 $ 167,977
- --------------------------------------------------------------------------------
Total operating revenue $1,224,345 $ 954,195 $ 784,067
Operating costs $1,030,442 $ 795,202 $ 635,795
Depreciation, depletion and
amortization $ 72,868 $ 53,480 $ 56,243
- --------------------------------------------------------------------------------
Operating income $ 121,035 $ 105,513 $ 92,029
================================================================================
EARNINGS PER SHARE
[GRAPH]
This graph illustrates consolidated earnings per share of $1.93 in 1996, $1.58
in 1995, and $1.34 in 1994.
RESULTS OF OPERATIONS - The continued 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 an increase in consolidated net income of $10 million
or 23.4% over the prior year. Earnings attributable to the regulated business
increased by $4 million in 1996 over the prior year as a result of reduced costs
and increased margins. The $6 million increase in net income for the
nonregulated business in 1996 over the prior year is primarily attributable to
the growth of the gas marketing operations as a result of weather related
demand and effectively combining gas supply and
17
<PAGE> 18
commodity derivative knowledge in order to match buyers and sellers. Use of
derivative instruments, such as futures contracts and swaps, allows ONEOK Gas
Marketing to accept physical supply and sale contracts which use different
price indices and hedge the price risk to the Company.
Net income rose 6.6 million in 1995 over the prior year as a result of increases
in regulated and nonregulated earnings of $1 million and $5.6 million,
respectively. The increased earnings of the nonregulated businesses is
primarily attributable to an increase in natural gas liquids production related
to the acquisition of oil and gas reserves in Louisiana and lower fuel and
shrink prices.
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, 1996, 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.
During 1996, 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 is 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 25 and note (h) to the consolidated financial statements.
ACCOUNTING POLICIES - The regulated operations of the Company are primarily
subject to accounting requirements of the Oklahoma Corporation Commission (OCC)
and the provisions of Statement of Financial Accounting 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 cost 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. In order
to align this view with its financial reporting, the Company, beginning this
year, is presenting the combined results of each operating environment.
Nonregulated segment data is reported by process rather than entity.
REGULATED OPERATIONS
Oklahoma Natural Gas is 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). Oklahoma Natural Gas Company, ONG Transmission Company, ONGSayre
Storage Company, and ONG Gas Gathering Company are consolidated for ratemaking
purposes by the Oklahoma Corporation Commission.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
FINANCIAL RESULTS
Gas Sales $487,294 $502,427 $524,961
Cost of gas 247,299 316,867 353,516
- --------------------------------------------------------------------------------
Gross margins on gas sales 239,995 185,560 171,445
Pipeline capacity lease margins 41,684 86,697 85,050
Other revenues 11,394 7,551 7,759
- --------------------------------------------------------------------------------
Net revenues 293,073 279,808 264,254
Operating expenses 144,927 146,986 135,139
Depreciation, depletion and
amortization 50,805 41,252 41,265
- --------------------------------------------------------------------------------
Operating income $ 97,341 $ 91,570 $ 87,850
================================================================================
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
VOLUMES (MMCF)
Gas sales
Residential 58,681 52,804 58,587
Commercial 29,918 25,288 27,342
Industrial 15,145 39,095 51,276
Pipeline capacity lease 158,527 134,130 120,619
- --------------------------------------------------------------------------------
Total 262,271 251,317 257,824
================================================================================
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
GROSS MARGIN PER MCF
Residential $2.92 $2.57 $2.13
Commercial $1.86 $1.88 $1.75
Industrial $ .84 $ .73 $1.79
Pipeline capacity leases $ .20 $ .47 $ .45
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Number of customers 729,467 724,201 715,142
Customers per employee 404 377 362
Capital expenditures
(thousands) $ 42,900 $ 55,800 $ 62,200
Identifiable assets
(thousands) $1,019,400 $1,023,000 $1,011,000
- --------------------------------------------------------------------------------
OPERATIONAL HIGHLIGHTS - In the last two rate cases, sweeping changes were
proposed to the way business had previously been conducted in order to be more
competitive and to stabilize and improve earnings capacity. The rate structure
that was approved shifted a significant amount of margin to core residential
and commercial customers, and offset that shift by gas cost reductions.
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
18
<PAGE> 19
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.
In 1996, significant changes occurred in the way the Company conducts its
business. Highlights of those changes are:
o Implemented a performance-based compensation system for all employees.
o Shifted the source of the net revenues from the industrial customer to the
core residential and commercial customers. In 1996, 80 percent of net
revenues was derived from gas sales and PCL revenues from the core
customers, as compared to 63 percent in 1995 and 1994. Despite this shift
in net revenues, the core customers experienced a net decrease in their
cost of gas due to changes in gas purchasing and pricing practices.
o Strengthened cost controls throughout the organization. Total employees
dropped by approximately six percent while increasing the number of
customers by approximately two percent. This was accomplished through
attrition and without compromising customer safety.
REGULATORY INITIATIVES - The OCC's NOI on restructuring Oklahoma's gas utility
industry has set into motion the process of unbundling products and services.
The Company believes and has stated in its response to the NOI that it
envisions a restructured rate environment in which competition replaces the
traditional regulated, full merchant utility function. The Company supports the
unbundling of at least the transmission, gathering, storage, customer service
and gas supply functions; 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. Unbundling of the
appropriate services could be accomplished within three to five years after
final OCC approval.
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 the separation of
the gas supply function, referred to in the industry as "open access", as the
first step in unbundling for small commercial and residential customers. The
Company intends to file for OCC permission for a pilot open access project
during the coming year and anticipates that open access can be accomplished
within two years after the OCC adopts the final rules.
RATE CASE ACTIVITIES - November 1994 Rate Order - Ratified a $23.7 million rate
increase of which $18.2 million had been approved on an interim basis in
February of 1992. The rate order also established a monthly connection fee that
will reduce the impact of seasonality of weather on earnings.
June 1995 Rate Order - Reduced the cost of service to the large industrial
customers and shifted the reduction to the core customers through a tariff
rider. Changes to gas purchasing and pricing practices offset the impact of the
tariff rider and provide a net savings to the customer. A temperature
normalization clause was adopted to further reduce the impact of seasonality on
earnings. As part of the settlement, the Company agreed not to file for a
general rate increase for two years.
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 1996 capital expenditure program
included $10 million for new business development and $2 million to improve
peak storage deliverability. It is the Company's practice to maintain and
periodically upgrade facilities to assure safe, reliable and efficient
operations.
OPERATING RESULTS - Higher gross margins on gas sales result primarily from
rate increases granted under the two rate cases completed in fiscal 1995 and
higher usage billed during the winter heating season which lasts from November
through April. Actual degree days in the 1996 heating season approximated
normal (3,632 degree days) and accordingly the Temperature Adjustment Clause
(TAC)
19
<PAGE> 20
had little impact on gas margins. Fluctuations in gas margins in 1995 and 1994
(prior to the implementation of the TAC) are directly attributable to weather
as evidenced by total degree days of 3,358 and 3,874 during the respective
winter heating seasons. 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. Despite an
increase in the spot market price of gas during 1996 from 1995, the Company
achieved a reduction in the cost of gas through changes in its gas purchasing
and pricing practices approved in the June 1995 rate case. Fluctuation in the
costs of gas from 1995 to 1994 reflects volume and spot market fluctuations.
The significant decrease in PCL margins reflects the rate restructuring
completed in 1995 which lowered rates to our large industrial customers in
order to compete more effectively.
Operating expenses remained relatively unchanged in 1996 as compared to 1995
despite an $8.7 million increase in post-retirement benefit expense. Prior to
the June 1995 rate case, such cost was deferred pending regulatory approval.
Offsetting this increase in expense were reductions in labor costs, property
damage claims and other operations and maintenance expenses. The increase in
operating expenses in 1995 as compared to 1994 reflects increases in
compensation relating to lump-sum incentive costs resulting from the attainment
of corporate performance objectives and the recognition of net periodic pension
costs previously deferred pending regulatory approval in the November 1994 rate
case.
NONREGULATED OPERATIONS
The Company's nonregulated operations are involved in the production,
processing and marketing of natural gas, oil and natural gas liquids. As a
result of acquisitions and dispositions during the third quarter of 1996, the
Company's producing properties are concentrated principally in Oklahoma where
it also owns nonoperated interests in 15 gas liquids extraction plants. 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.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
FINANCIAL RESULTS
Gas sales $ 612,595 $ 328,890 $ 168,848
Cost of gas 596,491 320,572 165,692
- --------------------------------------------------------------------------------
Gross margins on gas sales 16,104 8,318 3,156
Gas and oil production 25,181 20,799 23,664
Gas processing 73,337 67,217 63,591
Other 16,560 11,800 11,822
- --------------------------------------------------------------------------------
Net revenues 131,182 108,134 102,233
Operating costs 85,425 81,963 83,076
Depreciation, depletion
and amortization 22,063 12,228 14,978
- --------------------------------------------------------------------------------
Operating income $ 23,694 $ 13,943 $ 4,179
================================================================================
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
OPERATING INFORMATION
Natural gas volumes (MMcf)
Natural gas production 9,406 8,775 8,043
Residue gas 6,883 7,560 7,180
Marketing 315,616 221,561 83,541
- --------------------------------------------------------------------------------
331,905 237,896 98,764
- --------------------------------------------------------------------------------
Less intersegment sales
Natural gas production 3,978 1,640 --
Residue gas 6,880 5,095 --
Marketing 7,822 41,262 10,445
- --------------------------------------------------------------------------------
18,680 47,997 10,445
- --------------------------------------------------------------------------------
Net natural gas volumes 313,225 189,899 88,319
================================================================================
MARKETING
OPERATIONAL HIGHLIGHTS - The Company's marketing operation purchases and
markets natural gas, primarily in the mid-continent area of the United States.
Several operational changes instituted throughout the current year included
increased use of gas storage facilities, hedging and transportation
arbitraging. This allows the Company to capitalize on day-to-day pricing
volatility by managing positions and moving large volumes of gas in short
periods of time.
20
<PAGE> 21
Beginning in 1997, the Company expects to introduce ONEOK Producer Services, an
entity which will specialize in servicing small producers. Services will
include well connection identification and facilitation, production balancing
to nominated volumes and handling certain administrative accounting functions.
The Company has filed an application with FERC to market electricity.
Management anticipates that permits will be granted during the first quarter of
1997. It is not anticipated that such activities will be a major contributor to
earnings in 1997.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
MARKETING SEGMENT
Natural gas sales $ 612,595 $ 328,890 $ 168,848
Cost of gas 596,491 320,572 165,692
- --------------------------------------------------------------------------------
Gross margin on gas sales 16,104 8,318 3,156
Operating costs, net 2,697 3,458 (607)
Depreciation, depletion,
and amortization 484 80 --
- --------------------------------------------------------------------------------
Operating income $ 12,923 $ 4,780 $ 3,763
================================================================================
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
OPERATING INFORMATION
Natural gas volumes (MMcf) 315,616 221,561 83,541
Capital expenditures
(thousands) $ 370 $ 921 --
Identifiable assets
(thousands) $ 71,200 $ 41,400 $ 7,500
- --------------------------------------------------------------------------------
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 25.
OPERATING RESULTS - The increase in profitability of the marketing business
reflects the impact of the additional volume and price volatility resulting
from weather related demand. As important, the Company focuses on serving a
niche market of daily production trading. Such demand is precipitated by
customers who have volatile consumption throughout a month or acquire a portion
of their operating needs on the spot market as a method of hedging price
changes. This sector of the market is potentially more profitable due to spot
market volatility. In any one month, approximately 80 to 90 percent of the
Company's volume results from such trading. In January 1995, the Company
acquired the remaining 50 percent interest in a gas marketing entity. The
results of operations attributable to this investment are included in operating
costs prior to that date.
PROCESSING
OPERATIONAL HIGHLIGHTS - The Company's processing operation has nonoperating
interests in 15 gas processing plants whose operations include the extraction
and separation of natural gas liquids (NGLs) into distinct products (e.g.,
ethane, butane, propane and isobutane). Under certain market conditions it may
become unprofitable to separate and sell certain products, a process referred
to as rejection. Other 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.
Processing plant enhancement completed during 1996 included an expansion of the
gathering systems behind certain plants, development of producer alliances and
bringing most gas processing plants to capacity. The Company's joint interest
partner completed construction of a gathering system servicing
21
<PAGE> 22
three processing plants. Management is pursuing producer alliances which will
provide economical supplies and the dedication of additional production to the
plants. Currently, 12 of the Company's processing plants are on-line and
running at or near capacity.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
PROCESSING SEGMENT
Natural gas liquids
and residue sales $ 70,859 $ 64,726 $ 63,105
Other 261 148 2,298
- --------------------------------------------------------------------------------
Operating revenues 71,120 64,874 65,403
Operating costs 60,077 56,755 60,091
Depreciation, depletion,
and amortization 2,063 1,790 1,899
- --------------------------------------------------------------------------------
Operating income $ 8,980 $ 6,329 $ 3,413
================================================================================
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
OPERATING INFORMATION
Residue gas (MMcf) 6,883 7,560 7,180
Natural gas liquids
(MGallons) 195,979 205,464 194,378
Average NGL's price
(Gallons) 0.297 0.261 0.251
Fuel and shrink price
(MMbtu) $ 1.82 $ 1.64 $ 1.86
Capital expenditures
(thousands) $ 5,183 $ 1,226 $ 2,729
Identifiable assets
(thousands) $ 26,700 $ 25,200 $ 28,800
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES - The Company's portion of the gathering field addition
was approximately $3.2 million. The remaining $2 million in capital
expenditures during 1996 related to capital required to sustain operations.
Prior years' expenditures generally related to capital required to sustain
operations.
OPERATING RESULTS - Gas processing revenue rose, reflecting improving market
conditions for NGLs. NGL sales volumes were lower, due to rejection.
PRODUCTION
OPERATIONAL HIGHLIGHTS - The Company's strategy is to concentrate ownership of
hydrocarbon reserves in Oklahoma 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 intends to focus
on exploitation activities rather than exploratory drilling.
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,
1996, approximately 76 percent of anticipated gas production in 1997 has been
hedged primarily with swap agreements.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
PRODUCTION SEGMENT
Natural gas sales $ 17,466 $ 13,236 $ 16,036
Oil sales 7,716 7,563 7,628
Liquids and residue gas 2,477 2,491 486
Other 5,675 1,582 330
- --------------------------------------------------------------------------------
Operating revenues 33,334 24,872 24,480
Operating costs 11,341 11,257 11,573
Depreciation, depletion,
and amortization 19,161 10,038 12,172
- --------------------------------------------------------------------------------
Operating income $ 2,832 $ 3,577 $ 735
================================================================================
- --------------------------------------------------------------------------------
OPERATING INFORMATION 1996 1995 1994
- --------------------------------------------------------------------------------
Proved Reserves
Gas (MMcf) 74,068 39,226 32,370
Oil (MBbls) 1,795 3,247 2,284
- --------------------------------------------------------------------------------
Production
Gas (MMcf) 9,406 8,775 8,043
Oil (MBbls) 435 466 572
- --------------------------------------------------------------------------------
Average Price
Gas (Mcf) $ 1.85 $ 1.51 $ 1.95
Oil (BBls) $ 17.73 $ 16.22 $ 14.18
- --------------------------------------------------------------------------------
Capital Expenditures
(thousands) $ 46,733 $ 25,000 $ 8,327
Identifiable Assets
(thousands) $ 73,200 $ 60,000 $ 42,800
================================================================================
22
<PAGE> 23
CAPITAL EXPENDITURES - 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 related to a limited drilling program were approximately
$3.4 million, $5.9 million and $8.3 million in 1996, 1995 and 1994,
respectively.
OPERATING RESULTS - Net production revenues rose reflecting increased
production capabilities over the last two years and an increase in natural gas
prices during 1996 to 1994 levels. Other production revenue includes the gain
on sale of the Alabama and Mississippi properties in the third quarter of 1996.
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 a field by field basis rather than using a total company basis for
its proved properties. As a result, the Company recognized a pre-tax impairment
loss of $8.6 million in 1996.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW ANALYSIS
Cash provided by operating activities remains strong and continues as the
primary source for meeting cash requirements. However, due to seasonal
fluctuations and additional capital requirements, the Company accesses funds
through a short-term credit agreement 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
- --------------------------------------------------------------------------------
FOR THE YEARS ENDED AUGUST 31,
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Cash provided by operating activites $105,050 $109,559 $80,274
- --------------------------------------------------------------------------------
Income before deferred taxes and depreciation, depletion and amortization
increased by approximately $43 million in 1996 reflecting the overall increase
in net income, changes in the components of current and deferred taxes and the
recovery through rates of deferred costs settled in the 1995 rate proceedings.
This increase from earnings was partially offset by fluctuations in the level
of gas in storage and the timing of the recovery of gas costs. In late 1996,
the Company received permission from the OCC to change its method of recovering
purchased gas costs which had accumulated during the winter heating season
resulting from the base cost of gas set during the June 1995 rate proceeding.
In addition, the OCC will allow periodic changes in the base gas cost in order
to reduce the impact on cash flow of future fluctuations in the weighted
average cost of gas.
23
<PAGE> 24
Income before deferred taxes and depreciation, depletion and amortization was
$21 million lower in 1995 as compared to 1994 despite higher earnings in 1995,
reflecting changes in the components of current and deferred taxes. This was
offset by significant reductions in both gas in storage and the level of
recovery of purchased gas costs.
INVESTING CASH FLOW
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Cash used in investing activities $71,985 $63,299 $68,357
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES - Total capital expenditures increased in both 1996 and
1995; however, as discussed in the "Results from Operations," this is
attributable to the acquisition of production assets for approximately $43
million and $18 million in each of those years respectively. Capital
expenditures for 1997, excluding potential acquisitions, are estimated to be
$63 million.
CAPITAL EXPENDITURES AND ACQUISITIONS
---------------------------------------------------
1996 1995 1994
---------------------------------------------------
capital expenditures $52.3 $65.0 $73.9
---------------------------------------------------
capital acquisitions $43.1 $18.0 $0
---------------------------------------------------
[GRAPH]
This graph illustrates capital expenditures and acquisitions of $52,291,000
expenditures and $43,064,000 acquisitions in 1996, $64,157,000 expenditures and
$18,000,000 acquisitions in 1995 and $62,000,000 expenditures and $0.00
acqusitions in 1994.
ASSET SALES - Approximately $18 million and $8 million of proceeds were
received in 1996 and 1994, resulting from the sale of production and drilling
assets in 1996 and 1994, respectively. The sale of a pipeline investment for
its approximate book value generated approximately $10.2 million in proceeds in
1995.
FINANCING CASH FLOW
- -------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- -------------------------------------------------------------------------------
Cash used in financing activities $44,966 $38,306 $17,039
- -------------------------------------------------------------------------------
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 $125 million for general corporate purposes. A master note
with Bank of America provides an additional $30 million of borrowing capability.
The maximum amount of short-term debt authorized by the Board of Directors is
$150 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, 1996, the Company could have issued
approximately $292.5 million of additional long-term debt under the most
restrictive provisions contained in its various borrowing agreements. With the
current mix and relative sizes of the Company's businesses, Company goals are
to achieve an equity to capital ratio of approximately 50 percent and to
preserve or improve its current debt ratings. At August 31,1996, the equity
component was 51 percent as compared to 49 percent a year ago. Debt ratings are
A3 by Moody's Investor Service and A- by Standard and Poor's Corporation. No
long-term debt is currently callable, and only the 8.7 percent, 9.7 percent and
9.75 percent series have call options commencing in October 1996, and December
1999 and 2000, respectively. No long-term debt was issued in the last three
years.
STOCK AND DIVIDENDS - The Company had approximately 28 million shares of common
stock, 160,000 shares of preferred stock and 3 million shares of preference
stock available for issue at August 31, 1996, 1995 and 1994. Common stock
dividends were $1.18, $1.12 and $1.11 per share in 1996, 1995 and 1994,
respectively. Preferred stock dividends were $2.375 in each of the three years.
Through the
24
<PAGE> 25
Company's Stock Purchase and Dividend Reinvestment Program $2.04 million of
dividends were reinvested into common stock during 1996.
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, 1996, the net deferred gain on these contracts was
approximately $4.9 million.
NEW ACCOUNTING PRONOUNCEMENTS - In October 1995, the Financial Accounting
Standards Board issued SFAS No. 123, Accounting for Stock-Based Compensation,
which will become effective for years beginning after December 15, 1995. This
Statement will require that financial statements include certain disclosures
about stock-based employee compensation and allows, but does not require, a
fair value-based method of accounting for such compensation. The Company will
not adopt the fair value-based method of accounting, however, it will make the
required disclosures in future stockholder reports.
25
<PAGE> 26
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, 1996 and 1995, and for each of the years in the
three-year period ended August 31, 1996, 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.
26
<PAGE> 27
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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the results of their operations
and their cash flows for each of the years in the three-year period ended
August 31, 1996, in conformity with generally accepted accounting principles.
As discussed in Note A to the consolidated financial statements, effective
March 1, 1996, 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.
KPMG Peat Marwick LLP
Tulsa, Oklahoma
October 10, 1996
27
<PAGE> 28
ONEOK Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
Years Ended August 31, 1996 1995 1994
- -------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues
Regulated $ 538,169 $ 594,923 $ 616,090
Nonregulated:
Marketing 598,300 266,426 78,576
Processing 58,395 64,874 64,735
Production 25,479 24,042 23,024
Other 4,002 3,930 1,642
- -------------------------------------------------------------------------------------------
Total Nonregulated 686,176 359,272 167,977
- -------------------------------------------------------------------------------------------
Total Operating Revenues 1,224,345 954,195 784,067
- -------------------------------------------------------------------------------------------
Operating Expenses
Cost of gas 807,694 574,513 426,634
Operations and maintenance 201,259 200,443 190,118
Depreciation, depletion, and amortization 72,868 53,480 56,243
General taxes 21,489 20,246 19,043
Income taxes 33,037 25,342 21,095
- -------------------------------------------------------------------------------------------
Total Operating Expenses 1,136,347 874,024 713,133
- -------------------------------------------------------------------------------------------
Operating Income 87,998 80,171 70,934
- -------------------------------------------------------------------------------------------
Interest
Interest on long-term debt 31,748 32,401 32,988
Other interest 3,184 4,878 1,846
Amortization of debt expense 530 512 525
Allowance for funds used during construction (300) (424) (606)
- -------------------------------------------------------------------------------------------
Net Interest 35,162 37,367 34,753
- -------------------------------------------------------------------------------------------
Net Income 52,836 42,804 36,181
Preferred Stock Dividends 428 428 428
- -------------------------------------------------------------------------------------------
Income Available for Common Stock $ 52,408 $ 42,376 $ 35,753
===========================================================================================
Earnings Per Share of Common Stock $ 1.93 $ 1.58 $ 1.34
===========================================================================================
Average Shares of Common Stock
Outstanding (Thousands) 27,136 26,862 26,674
===========================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
28
<PAGE> 29
ONEOK Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
August 31, 1996 1995
- ----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Assets
Property
Distribution system $ 802,910 $ 680,446
Transmission system 258,870 338,596
Gas storage 4,195 4,235
Gas gathering 34,196 45,433
Oil and gas production 143,996 120,223
Gas processing 75,512 70,363
Other 16,973 16,447
- ----------------------------------------------------------------------------------
Total Property 1,336,652 1,275,743
Accumulated depreciation, depletion, and amortization 541,618 509,833
- ----------------------------------------------------------------------------------
Net Property 795,034 765,910
- ----------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 598 12,499
Accounts and notes receivable 119,338 81,768
Materials and supplies 5,136 5,803
Gas in storage 86,420 76,320
Advance payments for gas 5,764 6,214
Deferred income taxes -- 3,440
Purchased gas cost adjustment 11,677 --
Other current assets 4,213 10,042
- ----------------------------------------------------------------------------------
Total Current Assets 233,146 196,086
- ----------------------------------------------------------------------------------
Deferred Charges and Other Assets
Investments 2,279 17,077
Regulatory assets, net 155,253 166,923
Other 34,179 35,200
- ----------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 191,711 219,200
- ----------------------------------------------------------------------------------
Total Assets $1,219,891 $1,181,196
==================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
29
<PAGE> 30
ONEOK Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
August 31, 1996 1995
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Liabilities and Shareholders' Equity
Common Shareholders' Equity
Common Stock without par value: authorized 60,000,000
share; issued and outstanding 27,260,646 and 27,020,004
shares in 1996 and 1995 $ 207,084 $ 201,404
Retained earnings 207,611 187,225
- --------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 414,695 388,629
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 and 1995 9,000 9,000
- --------------------------------------------------------------------------------------------------
Total Shareholders' Equity 423,695 397,629
- --------------------------------------------------------------------------------------------------
Long-Term Debt 336,821 350,821
Current Liabilities
Long-term debt 15,050 13,050
Notes payable 50,223 55,275
Accounts payable 96,872 58,174
Accrued taxes 10,820 15,448
Accrued interest 7,732 7,922
Purchased gas cost adjustment -- 2,706
Customers' deposits 6,316 6,759
Deferred income taxes 3,427 --
Other 12,190 13,239
- --------------------------------------------------------------------------------------------------
Total Current Liabilities 202,630 172,573
- --------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 180,620 189,330
Customers' advances for construction
and other deferred credits 76,125 70,843
- --------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 256,745 260,173
- --------------------------------------------------------------------------------------------------
Commitments and Contingencies - -
- --------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $1,219,891 $1,181,196
==================================================================================================
</TABLE>
30
<PAGE> 31
ONEOK Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
Years Ended August 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Net Income $ 52,836 $ 42,804 $ 36,181
Depreciation, depletion, and amortization 72,868 53,480 56,243
Net losses of equity investees 173 811 1,455
Deferred income taxes (2,038) (15,270) 10,021
Other (5,675) 613 (528)
Changes in assets and liabilities:
(Increase) decrease in accounts and notes receivable (37,570) (32,726) 2,466
(Increase) decrease in inventories (9,433) 12,331 (1,547)
(Increase) decrease in other assets 8,027 5,816 (1,812)
(Increase) decrease in regulatory assets 1,431 (2,981) (24,866)
Increase (decrease) in accounts payable and
accrued liabilities 33,532 22,400 2,733
Changes in purchased gas cost adjustment (14,383) 14,515 (20,658)
(Increase) decrease in deferred credits
and other liabilities 5,282 7,766 20,586
- -----------------------------------------------------------------------------------------------
Cash provided by operating activities 105,050 109,559 80,274
- -----------------------------------------------------------------------------------------------
Investing Activities
(Increase) decrease in other investments -- 5,226 (2,324)
Proceeds from sale of investment -- 10,901 --
Capital expenditures, net (89,582) (80,982) (73,999)
Proceeds from sale of property 17,597 1,556 7,966
- -----------------------------------------------------------------------------------------------
Cash used in investing activities (71,985) (63,299) (68,357)
- -----------------------------------------------------------------------------------------------
Financing Activities
Payments of long-term debt (12,000) (12,971) (15,000)
Net issuance (payments) of notes payable (5,052) 5,170 28,000
Dividends paid (27,914) (30,505) (30,039)
- -----------------------------------------------------------------------------------------------
Cash used in financing activities (44,966) (38,306) (17,039)
- -----------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents (11,901) 7,954 (5,122)
Cash and Cash Equivalents at the
Beginning of Year 12,499 4,545 9,667
- -----------------------------------------------------------------------------------------------
Cash and Cash Equivalents at
End of Year $ 598 $ 12,499 $ 4,545
===============================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE> 32
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, 1993 $ 194,365 $ 168,784 $ 363,149 $ 9,000
Net income -- 36,181 36,181 --
Issuance of common stock 1,203 -- 1,203 --
Preferred stock dividends -
$2.375 per share -- (428) (428) --
Common stock dividends -
$1.11 per share -- (29,611) (29,611) --
- -------------------------------------------------------------------------------------------
Balance at August 31, 1994 $ 195,568 $ 174,926 $ 370,494 $ 9,000
===========================================================================================
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
===========================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE> 33
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 1996 generated approximately 80 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, operate and lease
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) and the
Railroad Commission of Texas. 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
Reulations". 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 commission's 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 reulatory
asset and amortized to expense as it is recovered through rates. Total
regulatory assets resulting from this deferal process are approximately $155
million and $167 million at August 31, 1996 and 1995 respectively. See
footnote 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 contains a temperature normalization clause that
provides for billing adjustments from acutal 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 (8.50 percent, 8.24 percent, and 8.21
percent, in 1996, 1995, and 1994, respectively) used during the construction of
major projects and is recorded as a credit to earnings.
Depreciation is calculated using the straight-line method based upon rates
prescribed for ratemaking purposes. The average depreciation rate approximated
3.6 percent in 1996, 3.7 percent in 1995, and 3.8 percent in 1994.
<TABLE>
<CAPTION>
Average Service
Life (Years)
----------------------------------------
<S> <C>
Distribution Property 15 - 40
Gathering Property 14 - 47
Storage Property 35 - 40
Transmission Property 14 - 47
Other Property 6 - 40
----------------------------------------
</TABLE>
Maintenance and repairs are charged directly to expense. Generally, the cost of
property retired or sold, plus removal costs, less salvage, is charged to
accumulated depreciation. Gains and losses from sales or transfers of operating
units or systems are recognized in income.
PRODUCTION PROPERTY - The Company uses the successful-efforts method to account
for costs incurred in the acquisition and exploration of oil and natural gas
reserves. Costs to acquire mineral interests in proved reserves, and to drill
and equip development wells are capitalized. Geological and geophysical costs
and costs to drill exploratory wells which do not find proved reserves are
expensed. Unproved
33
<PAGE> 34
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.
Current gas in storage is valued using the last-in, first-out method. The
estimated replacement cost of current gas in storage was $81.5 million at
August 31, 1996, and $72.4 million at August 31, 1995.
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 existing physical gas
purchase or sale commitments. Gains and losses resulting from changes in market
value of the various derivative instruments utilized as hedges are recognized
in income when the underlying physical transaction is closed.
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 in its year-end reserve study, 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
aggregates 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 - The Company follows the intrinsic value
method of accounting for common stock options and awards issued to employees.
34
<PAGE> 35
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 1995 and 1994 consolidated financial
statements have been reclassified to conform with the 1996 presentation.
(B) REGULATORY ASSETS
The following table is a summary of regulatory assets, net of amortization:
- --------------------------------------------------------------------------------
AUGUST 31, 1996 1995
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
Recoupable take-or-pay settlements $ 100,155 $ 104,746
Pension costs 33,426 37,607
Postretirement costs other than pensions 9,386 10,603
Postemployment benefit costs 2,975 2,975
Income tax rate changes 8,354 8,887
Unamortized gas storage costs 957 2,105
- --------------------------------------------------------------------------------
Regulatory assets, net $ 155,253 $ 166,923
================================================================================
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 205
Income tax rate changes - 1990 178
Income tax rate changes - 1993 194
Unamortized gas storage costs 10
- ----------------------------------------------------------
</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.
The Company incurred approximately $3.1 million of recoupable costs
attributable to resolutions of take-or-pay and pricing issues during 1995. No
additional costs were incurred in 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
$11.7 million, $8.2 million, and $3.1 million in 1996, 1995, and 1994,
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, 1996, 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 $125 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 .075 percent applied annually to the total line of credit.
Borrowings under the agreement bear interest at offshore IBOR rates plus .200
percent per annum. No compensating balance requirements existed at August 31,
1996. A master note with Bank of America provides an additional $30 million of
borrowing capability.
Short-term notes payable totaling $50.2 million at August 31, 1996, and $55.3
million at August 31, 1995, were outstanding. The notes carried average
interest rates of 5.61 percent and 6.16 percent, respectively.
35
<PAGE> 36
(D) LONG-TERM DEBT
All long-term notes payable at August 31, 1996, are unsecured. The aggregate
current maturities of long-term debt for each of the five years ending August
31, 2001, are $15.1 million; $15.1 million; $13.1 million; $16.1 million; and
$14.7 million, respectively, including $1.1 million each year callable at the
option of the holder.
- --------------------------------------------------------------------------------
AUGUST 31, 1996 1995
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
Long-Term Notes Payable
5.00% due 1996 $ -- $ 12,000
5.57% due 1997 14,000 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
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 $ 351,871 363,871
- --------------------------------------------------------------------------------
Current maturities of
long-term debt 15,050 13,050
- --------------------------------------------------------------------------------
Long-term notes payable $ 336,821 $ 350,821
- --------------------------------------------------------------------------------
(E) CAPITAL STOCK
The holders of Series A preferred stock have full voting rights (two votes per
share) and may redeem those shares in whole or in part at any time at the
option of the Company. Holders are entitled to $53 per share, plus all
dividends accrued or in arrears thereon, upon voluntary redemption or
liquidation and $50 per share upon involuntary liquidation. No dividends were
in arrears at August 31, 1996.
The Company has authorized three million shares of preference stock, none of
which was outstanding at August 31, 1996, and approximately 28 million shares
of unrestricted common stock available for issue. The Board has reserved two
million shares of the Company's common stock for the Direct Stock Purchase and
Dividend Reinvestment Plan of which 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.
In 1996, the Company approved the Key Employee Stock Plan which provides for
compensation of certain officers and key employees with common stock or cash
through various types of awards, including stock options, stock bonus,
performance units and restricted stock. To date, 100,000 fixed options have
been granted at an exercise price of $23.69; no options are exercisable by the
employee until November 1996. No other awards have been granted. 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. The Board has reserved 1,000,000 shares
of common stock for this plan.
Also in 1996, the Company approved the Employee Stock PurchasePlan which is a
non-compensatory plan that allows substantially all employees to purchase
common stock at a 15 percent discount. The Board has reserved 350,000 shares of
common stock for this plan.
Under the most restrictive covenants of the Company's loan agreements, $192.4
million (87.5 percent) of retained earnings at August 31, 1996, was available
to pay dividends.
36
<PAGE> 37
(F) INCOME TAXES
The provisions for income taxes are as follows:
- -------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- -------------------------------------------------------------------------------
Current income taxes
Federal $ 29,926 $ 34,837 $ 9,874
State 5,150 5,775 1,201
- -------------------------------------------------------------------------------
Total current income taxes $ 35,076 $ 40,612 $ 11,075
================================================================================
Deferred income taxes
Federal $ (1,766) $ (13,007) $ 8,555
State (272) (2,263) 1,466
- -------------------------------------------------------------------------------
Total deferred income taxes $ (2,038) $ (15,270) $ 10,021
================================================================================
Following is a reconciliation of the provision for income taxes.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Pretax income $ 85,874 $ 68,146 $ 57,277
Federal statutory income tax rate 35.00% 35.00% 35.00%
- --------------------------------------------------------------------------------
Provision for federal income taxes 30,056 23,851 20,047
Amortization of distribution property
investment tax credits (727) (739) (739)
State income taxes, net of credits and
federal tax benefit 3,548 2,372 1,549
Other, net 160 (142) 238
- --------------------------------------------------------------------------------
Actual income tax expense $ 33,037 $ 25,342 $ 21,095
================================================================================
At August 31, 1996, the Company had $2.1 million in deferred investment tax
credits recorded in other deferred credits which will be amortized over the
next three 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.
- --------------------------------------------------------------------------------
AUGUST 31, 1996 1995
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
Deferred Tax Assets
Investment write-down $ 1,373 $ 1,373
Accrued liabilities not deductible until paid 7,016 5,099
Net operating loss carryforwards 754 800
Regulatory assets 2,601 5,518
Other 2,052 1,789
- --------------------------------------------------------------------------------
Total deferred tax assets 13,796 14,579
Valuation allowance for net operating loss
carryforwards expected to expire prior to
utilization 754 800
- --------------------------------------------------------------------------------
Net deferred tax assets 13,042 13,779
Deferred Tax Liabilities
Excess of tax over book depreciation and depletion 133,207 131,485
Investment in joint ventures -- 5,394
Regulatory assets 60,753 59,294
Other 3,129 3,496
- --------------------------------------------------------------------------------
Gross deferred tax liabilities 197,089 199,669
- --------------------------------------------------------------------------------
Net Deferred Tax Liabilities $184,047 $185,890
================================================================================
37
<PAGE> 38
The Company had remaining net operating loss carry-forwards for state income
tax purposes of approximately $13.3 million at August 31, 1996, 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.
Net pension costs, as determined by an independent actuary, included the
following:
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Service cost $ 5,957 $ 6,078 $ 6,518
Interest cost 23,525 22,659 20,599
Actual return on assets (72,138) (27,438) (12,404)
Net amortization and deferral 50,337 6,920 (6,761)
- --------------------------------------------------------------------------------
Net pension cost $ 7,681 $ 8,219 $ 7,952
================================================================================
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.
- --------------------------------------------------------------------------------
AUGUST 31, 1996 1995
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
Actuarial present value of vested benefit obligation $(268,296) $(254,138)
Accumulated benefit obligation (281,363) $(266,227)
Projected benefit obligation (314,866) $(311,526)
Plan assets at fair value, principally equity
securities and an IPG fund 328,459 269,180
- --------------------------------------------------------------------------------
Plan assets more (less) less than projected
benefit obligation 13,593 (42,346)
Unrecognized net loss (863) 59,172
Unrecognized prior service cost 149 672
Unrecognized net asset (3,739) (4,206)
- --------------------------------------------------------------------------------
Prepaid pension cost $ 9,140 $ 13,292
================================================================================
The projected benefit obligation was determined using an annual discount rate
of 7.75 percent for 1996 and 1995; a long-term rate of return on plan assets of
8 percent and 9 percent for 1996 and 1995, respectively; and an average assumed
long-term annual rate of salary increases of 4 percent and 5 percent for 1996
and 1995, respectively.
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.
38
<PAGE> 39
Net periodic postretirement benefit cost includes the following components:
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995
- --------------------------------------------------------------------------------
Service cost $ 1,704 $ 1,820
Interest cost 5,668 5,282
Net amortization and deferral 3,608 3,608
- --------------------------------------------------------------------------------
Net periodic postretirement benefit cost $ 10,980 $ 10,710
================================================================================
For measurement purposes, an 8.85 percent annual rate of increase in the per
capita cost of covered medical benefits (i.e., medical cost trend rate) was
assumed for 1996, the rate was assumed to decrease gradually to 5.0 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, 1996, by $10.9 million and the aggregate of the service and interest
cost components of net periodic postretirement benefit cost for the year ended
August 31, 1996, by $1.4 million.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.75 percent at August 31, 1996.
The following table presents the plan's funded status reconciled with amounts
recognized in the Company's consolidated balance sheet.
- --------------------------------------------------------------------------------
AUGUST 31, 1996 1995
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
Accumulated Postretirement Benefit Obligation
Retirees $ (49,500) $ (48,164)
Fully eligible active plan participants (3,246) (4,176)
Other active plan participants (21,708) (22,868)
- --------------------------------------------------------------------------------
Accumulated postretirement benefit obligation (74,454) (75,208)
Unrecognized transition obligation 61,341 64,949
Unrecognized net gain (9,071) (6,050)
- --------------------------------------------------------------------------------
Accrued postretirement benefit cost $ (22,184) $ (16,309)
================================================================================
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 $3.7
million in 1996; $3.4 million in 1995; and $3.7 million in 1994 .
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.
39
<PAGE> 40
(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.
- --------------------------------------------------------------------------------
APPROXIMATE
(THOUSANDS OF DOLLARS) BOOK VALUE FAIR VALUE
- --------------------------------------------------------------------------------
AUGUST 31, 1996
Cash and cash equivalents $ 598 $ 598
Accounts and notes receivable $ 119,338 $ 119,338
Natural gas swaps -- $ 2,924
Natural gas options -- $ 78
Long-term debt and notes payable $ 351,871 $ 377,383
- --------------------------------------------------------------------------------
AUGUST 31, 1995
Cash and cash equivalents $ 12,499 $ 12,499
Accounts and notes receivable $ 81,768 $ 81,768
Long-term debt and notes payable $ 363,871 $ 393,000
- --------------------------------------------------------------------------------
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. 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 ) 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 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 manage margins and to limit overall price risk exposure. None of
these derivatives are held for speculative purposes and, in general, the
Company's risk managment policy requires that positions taken with derivatives
be offset by positions in physical transactions or other derivatives.
The total notional value of futures purchased and sold is $99.6 million and
$101 million, respectively, at August 31, 1996. The term "notional amount"
refers to the current contract unit price times the contract volume for the
relevant derivative. In general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative of the Company's level of activity in such derivatives,
although the amounts at risk are significantly
40
<PAGE> 41
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.
- --------------------------------------------------------------------------------
(VOLUMES IN MCF, THOUSANDS OF DOLLARS)
ESTIMATED FAIR
VOLUME VOLUME MARKET VALUE
AUGUST 31, 1996 PURCHASED SOLD GAIN (LOSS)(A)
- --------------------------------------------------------------------------------
Options -- 1,335 $ 78
Swaps 178,632 178,432 $ 2,924
Futures 54,680 53,460 $ 1,935
- --------------------------------------------------------------------------------
(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.
There were no material amounts of options, swaps or contracts outstanding at
August 31, 1995 and 1994.
NYMEX-traded futures and option contracts are guaranteed by NYMEX 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 counterparts 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 traded futures
and options contracts require daily cash settlement in margin accounts with
brokers.
41
<PAGE> 42
(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, and the Company's former
contract drilling business, which was sold effective May 1, 1994.
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>
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 26.0 64.3
- ------------------------------------------------------------------------------------------------------
Total revenues $ 540.4 $ 613.8 $ 71.1 $ 33.4 $ 30.0 $1,288.7
- ------------------------------------------------------------------------------------------------------
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 12.4 77.9
- ------------------------------------------------------------------------------------------------------
Total revenues $ 596.7 $ 329.3 $ 64.9 $ 24.9 $ 16.3 $1,032.1
- ------------------------------------------------------------------------------------------------------
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
======================================================================================================
1994
Sales to unaffiliated customers $ 616.1 $ 78.6 $ 64.8 $ 23.0 $ 1.6 $ 784.1
Intersegment sales 1.7 91.6 0.6 1.5 10.9 106.3
- ------------------------------------------------------------------------------------------------------
Total revenues $ 617.8 $ 170.2 $ 65.4 $ 24.5 $ 12.5 $ 890.4
- ------------------------------------------------------------------------------------------------------
Operating income (loss)
before income taxes $ 87.8 $ 3.8 $ 3.4 $ 0.7 $ (3.7) $ 92.0
Identifiable assets $1,011.0 $ 7.5 $ 28.8 $ 42.8 $ 58.0 $1,148.1
Depreciation, depletion, and
amortization $ 41.3 $ 0.0 $ 1.9 $ 12.2 $ 0.9 $ 56.3
Capital expenditures $ 62.2 $ 0.0 $ 2.7 $ 8.3 $ 0.7 $ 73.9
======================================================================================================
</TABLE>
42
<PAGE> 43
(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 1996, 1995,
and 1994. Estimated future minimum rental payments for the lease are $5.8
million for each of the years ended August 31, 1997 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.
The Company has the right to sublet excess office space in ONEOK Plaza. The
Company received $2.5 million, $2.4 million, and $2.1 million in rental revenue
during 1996, 1995, and 1994, respectively, for various subleases. Estimated
minimum future rental payments to be received under existing contracts for
subleases are: $2.5 million in 1997; $2.0 million in 1998; $1.4 million in
1999; $1.1 million in 2000, $1.1 million in 2001; and a total of $3.5 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:
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Capitalized costs at end of year:
Unproved properties $ 11,330 $ 5,030 $ 6,363
Proved properties 129,035 111,459 94,507
- --------------------------------------------------------------------------------
Total Capitalized Costs 140,365 116,489 100,870
Accumulated depreciation, depletion,
and amortization 74,129 65,376 61,052
- --------------------------------------------------------------------------------
Net Capitalized Costs $ 66,236 $ 51,113 $ 39,818
================================================================================
Costs incurred during the year:
Property acquisition costs (unproved) $ 231 $ 926 $ 1,021
Exploration costs $ 601 $ 1,228 $ 2,731
Development costs $ 2,811 $ 4,839 $ 4,729
Purchase of minerals in place $ 43,064 $ 15,099 $ 101
- --------------------------------------------------------------------------------
The accompanying schedule presents the results of operation for the Company's
oil and gas production activities. The results exclude general office overhead
and interest expense attributable to oil and gas production.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Net revenues from production:
Sales to unaffiliated customers $ 25,478 $ 24,042 $ 23,023
Gas sold to affiliates 7,856 830 1,457
- --------------------------------------------------------------------------------
Net revenues from production 33,334 24,872 24,480
- --------------------------------------------------------------------------------
Production costs 5,494 4,565 4,912
Exploration expenses 574 680 1,419
Depreciation, depletion, and amortization 18,552 9,447 12,048
Income tax expense 3,311 3,868 2,222
- --------------------------------------------------------------------------------
Total expenses 27,931 18,560 20,601
- --------------------------------------------------------------------------------
Results of operations from
producing activities $ 5,403 $ 6,312 $ 3,879
================================================================================
43
<PAGE> 44
(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 1996, 1995, and 1994 fiscal
years.
- --------------------------------------------------------------------------------
OIL GAS
PROVED RESERVES (MBBLS) (MMCF)
- --------------------------------------------------------------------------------
September 1, 1993 2,832 38,790
Revisions of prior estimates (201) (756)
Extensions, discoveries, and other additions 224 2,264
Purchases of minerals in place 1 115
Production (572) (8,043)
- --------------------------------------------------------------------------------
August 31, 1994 2,284 32,370
Revisions of prior estimates 579 83
Extensions, discoveries, and other additions 241 4,002
Purchases of minerals in place 637 11,931
Sales of minerals in place (28) (386)
Production (466) (8,774)
- --------------------------------------------------------------------------------
September 1, 1995 3,247 39,226
Revisions of prior estimates (274) (1,258)
Extensions, discoveries, and other additions 41 5,089
Purchases of minerals in place 928 42,347
Sales of minerals in place (1,712) (1,930)
Production (435) (9,406)
- --------------------------------------------------------------------------------
August 31, 1996 1,795 74,068
================================================================================
Proved developed reserves:
August 31, 1993 2,352 34,792
August 31, 1994 1,943 29,193
August 31, 1995 3,068 36,946
August 31, 1996 1,427 60,497
- --------------------------------------------------------------------------------
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's petroleum engineers and geologists 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.
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Future cash inflows $173,166 $111,370 $ 98,270
Future production and development costs 53,491 29,684 26,103
Future income tax expense 21,245 16,375 16,278
- --------------------------------------------------------------------------------
Future net cash flows 98,430 65,311 55,889
10 percent annual discount for estimated
timing of cash flows 31,114 17,484 15,660
- --------------------------------------------------------------------------------
Standardized measure of discounted future
net cash flows relating to oil and gas
reserves $ 67,316 $ 47,827 $ 40,229
================================================================================
44
<PAGE> 45
The changes in standardized measure of discounted future net cash flows
relating to proved oil and gas reserves are as follows:
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Beginning of year $ 47,827 $ 40,229 $ 48,628
Changes resulting from:
Sales of oil and gas produced, net of
production costs (19,687) (16,234) (19,238)
Net changes in price, development, and
production costs 4,054 (4,874) (3,839)
Extensions, discoveries, additions, and
improved recovery, less related costs 6,056 6,377 5,112
Purchases of minerals in place 42,999 14,707 126
Sales of minerals in place (20,962) (871) --
Revisions of previous quantity estimates (114) 5,520 (2,379)
Accretion of discount 3,885 5,107 6,360
Net change in income taxes (2,538) (274) 3,260
Other, net 5,796 (1,860) 2,199
- --------------------------------------------------------------------------------
End of year $ 67,316 $ 47,827 $ 40,229
================================================================================
(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 1996 and 1995 follows:
<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)
Income taxes $ 5,276 $ 23,840 $ 7,746 $ (3,825)
Net income $ 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>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
Quarter
- --------------------------------------------------------------------------------------------------
1995 First Second Third Fourth
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
<S> <C> <C> <C> <C>
Operating revenues
Regulated $ 126,025 $ 244,687 $ 144,551 $ 79,660
Nonregulated $ 39,755 $ 41,813 $ 157,726 $ 119,978
Operating income $ 21,907 $ 55,937 $ 23,253 $ 4,416
Income taxes $ 4,835 $ 17,811 $ 4,810 $ (2,114)
Net income $ 7,788 $ 28,287 $ 9,040 $ (2,311)
Earnings per share of common stock $ 0.29 $ 1.05 $ 0.33 $ (0.09)
Dividends per share of common share $ 0.28 $ 0.28 $ 0.28 $ 0.28
Average shares of common stock
outstanding (thousands) 26,690 26,712 27,020 27,020
- --------------------------------------------------------------------------------------------------
</TABLE>
45
<PAGE> 46
(O) SUPPLEMENTAL CASH FLOW INFORMATION
- --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS) 1996 1995 1994
- --------------------------------------------------------------------------------
Cash Paid During the Year
Interest (including amount capitalized) $35,122 $37,642 $34,694
Income taxes $40,642 $34,513 $14,948
Noncash Transactions:
Gas received as payment in kind $ 2,395 $86,033 $74,584
Issuance of common stock related to:
Stock Performance Plan $ 1,144 -- $ 1,203
Acquisition of gas marketing
partnership -- $ 5,836 --
Dividend reinvestment plan $ 4,536 -- --
Distribution of net assets
from partnership $14,625 -- --
- --------------------------------------------------------------------------------
46
<PAGE> 47
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 1996
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 1996 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 1996 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 1996 definitive Proxy Statement, which is incorporated herein by this
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
47
<PAGE> 48
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.
48
<PAGE> 49
(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, filed herewith on pages 55 through 63.
(21) Required information concerning the registrant's subsidiaries is
included in Item 1. of this Form 10-K.
(24) Independent Auditors' Consent, filed herewith on page 64.
(27) Financial Data 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.
49
<PAGE> 50
Page No.
--------
(2) Financial Statements
(a) Independent Auditors' Report 27
(b) Consolidated Statements of Income for the
years ended August 31, 1996, 1995, and 1994 28
(c) Consolidated Balance Sheets at August 31, 1996 and 1995 29-30
(d) Consolidated Statements of Cash Flows for the
years ended August 31, 1996, 1995, and 1994 31
(e) Consolidated Statements of Shareholders'Equity
for the years ended August 31, 1996, 1995, and 1994 32
(f) Notes to Consolidated Financial Statements 33-46
(3) Financial Statement Schedules
None.
(B) REPORTS ON FORM 8-K
None.
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.
50
<PAGE> 51
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 17th day of
October, 1996.
ONEOK Inc.
Registrant
By: J. D. NEAL
----------------------------------
J. D. Neal
Vice President, Chief Financial
Officer, and Treasurer (Principal
Financial and Accounting Officer)
51
<PAGE> 52
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 17th day of October, 1996.
LARRY W. BRUMMETT J. D. NEAL
- ----------------------------- -----------------------------
Larry W. Brummett J. D. Neal
Chairman of the Board, Vice President, Chief
President, Chief Executive Financial Officer, and
Officer, and Director Treasurer (Principal Financial
and Accounting Officer)
E. G. ANDERSON D. A. NEWSOM
- ----------------------------- -----------------------------
E. G. Anderson D. A. Newsom
Director Director
W. M. BELL G. D. PARKER
- ----------------------------- -----------------------------
W. M. Bell G. D. Parker
Director Director
D. R. CUMMINGS J. D. SCOTT
- ----------------------------- -----------------------------
D. R. Cummings J. D. Scott
Director Director
W. L. FORD S. L. YOUNG
- ----------------------------- -----------------------------
W. L. Ford S. L. Young
Director Director
J. M. GRAVES
- -----------------------------
J. M. Graves
Director
S. J. JATRAS
- -----------------------------
S. J. Jatras
Director
D. L. KYLE
- -----------------------------
D. L. Kyle
Director
B. H. MACKIE
- -----------------------------
B. H. Mackie
Director
52
<PAGE> 53
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.
(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.
53
<PAGE> 54
(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, filed herewith on pages 55 through 63.
(21) Required information concerning the registrant's subsidiaries is
included in Item 1. of this Form 10-K.
(24) Independent Auditors' Consent, filed herewith on page 64.
(27) Financial Data 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.
54
<PAGE> 1
Exhibit (10)(o)
THIRD AMENDMENT TO CREDIT AGREEMENT
THIS THIRD AMENDMENT TO CREDIT AGREEMENT is made and dated as of August
15, 1996 (the "THIRD 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 and a
Second Amendment dated as of August 17, 1995 (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 15, 1996" and inserting "August
13, 1997" 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, 0.20% per annum."
2.3 Section 5.5 shall be amended by deleting "August 31, 1994" and
inserting "August 31, 1995" and by deleting "November 30, 1994, February 28,
1995 and May 31, 1995" and inserting "November 30, 1995, February 28, 1996 and
May 31, 1996" in lieu thereof.
2.4 Section 5.11(b) shall be amended by deleting "August 31, 1994"
and inserting "August 31, 1995" in lieu thereof.
2.5 Schedules 1.1 and 3 attached to the Credit Agreement are
hereby deleted and Schedule 1.1 and 3 attached to this Third 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 Third Amendment:
3.1 Authorization. The execution, delivery and performance of this
Third Amendment have been duly authorized by all necessary corporate action by
the Company and this Third Amendment has been duly executed and delivered by
the Company.
3.2 Binding Obligation. This Third Amendment is the legal, valid
and binding obligation of Company, enforceable against the Company in
accordance with its terms.
55
<PAGE> 2
3.3 No Legal Obstacle to Agreement. The execution, delivery and
performance of this Third 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 Third
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 Third
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 Authorized Signatories. A certificate, signed by the Secretary
or an Assistant Secretary of the Company and dated the date of this Third
Amendment, as to the incumbency of the person or persons authorized to execute
and deliver this Third 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 Third 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 Third 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 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 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.
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,
Bank IV of Oklahoma, N.A. and The Bank of Nova Scotia shall no longer be
parties to this Agreement.
56
<PAGE> 3
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 Third 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 Third 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 Third 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 Third Amendment shall be governed by and
construed under the laws of the State of California.
57
<PAGE> 4
IN WITNESS WHEREOF, the parties hereto have caused this 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, Treasurer,
Chief Financial Officer, and
Chief Accounting Officer
BANK OF AMERICA NATIONAL TRUST AND
SAVINGS ASSOCIATION, as Agent
By: PEGGY FUJIMOTO
Title: Vice President
BANK OF AMERICA NATIONAL TRUST AND
SAVINGS ASSOCIATION, as a Bank
By: VANESSA SHEH MEYER
Title: Vice President
TEXAS COMMERCE BANK NATIONAL ASSOCIATION
By: DONNA GERMAN
Title: Senior Vice President
MELLON BANK, N.A.
By: SCOTT HENNESSEE
Title: Assistant Vice President
BANK OF OKLAHOMA, N.A.
By: JANE FAULKENBERRY
Title: Vice President
FIRST SOUTHWEST BANK OF FREDERICK
By: GREG BOUDREAU
Title: Assistant Vice President
(Signatures continue)
58
<PAGE> 5
BOATMEN'S FIRST NATIONAL BANK
OF OKLAHOMA
By: HAYDEN HYDE
Title: Senior Vice President
LIBERTY BANK & TRUST COMPANY OF
OKLAHOMA CITY, N.A.
By: LAURA CHRISTOFFERSON
Title: Vice President
LIBERTY BANK & TRUST CO. OF TULSA, N.A.
By: ROBERT D. MATTAX
Title: Vice President
THE STILLWATER NATIONAL BANK AND
TRUST COMPANY
By: DAVID W. PITTS
Title: Vice President
CITIZENS BANK OF LAWTON
By: DAN TORBETT
Title: Executive Vice President
WESTAR BANK OF BARTLESVILLE
By: DAVID KEDY
Title: Senior Vice President
NATIONSBANK OF TEXAS, N.A.
By: CURTIS L. ANDERSON
Title: Senior Vice President
BANK ONE, OKLAHOMA CITY
By: JAMES R. KARCHER
Title: Senior Vice President
59
<PAGE> 6
BANK IV OF OKLAHOMA, N.A. (as a Selling
Bank for purposes of Section 5.1 only)
By: HAYDEN HYDE
Title: Senior Vice President
THE BANK OF NOVA SCOTIA (as a Selling
Bank for purposes of Section 5.1 only)
By: F. C. H. ASHBY
Title: Senior Manager, Loan Operations
60
<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 $31,000,000 24.80%
Texas Commerce Bank
National Association 21,000,000 16.80%
Mellon Bank, N.A. 12,000,000 9.60%
Bank of Oklahoma, N.A. 14,000,000 11.20%
Boatmen's First National Bank
of Oklahoma 12,000,000 9.60%
Liberty Bank & Trust Company
of Oklahoma City, N.A. 8,000,000 6.40%
Liberty Bank & Trust Co.
of Tulsa, N.A. 6,000,000 4.80%
The Stillwater National Bank
and Trust Company 1,000,000 0.80%
Citizens Bank of Lawton 1,000,000 0.80%
Westar Bank of Bartlesville 1,000,000 0.80%
Nations Bank of Texas, N.A. 15,000,000 12.00%
Bank One, Oklahoma City 2,000,000 1.60%
First Southwest Bank of Frederick 1,000,000 .80%
- --------------------------------------------------------------------------------------------------
TOTAL: $125,000,000 100.00%
- --------------------------------------------------------------------------------------------------
</TABLE>
61
<PAGE> 8
SCHEDULE 3
OFFSHORE AND DOMESTIC LENDING OFFICES
ADDRESSES FOR NOTICES
<TABLE>
<S> <C>
DONNA GERMAN ROBERT D. MATTAX
Texas Commerce Bank N.A. Liberty Bank & Trust Company of Tulsa
P.O. Box 660197 Fourth Floor
Dallas, TX 75266-0197 15 East Fifth Street
Phone: (214) 922-2540 Tulsa, OK 74103
Fax: (214) 922-2389 Phone: (918) 586-5179
Fax: (918) 586-5952
JANE A. FAULKENBERRY JAMES R. KARCHER
Bank of Oklahoma Bank One, Oklahoma City
Eighth Floor 6303 North Portland
One Williams Center Oklahoma City, OK73112
Tulsa, OK 74172 Phone: (405) 272-2860
Phone: (918) 588-6272 Fax: (405) 272-7528
Fax: (918) 588-6880
LAURA L. CHRISTOFFERSON SCOTT HENNESSEE
Liberty National Bank and Trust Company Mellon Bank
100 North Broadway One Mellon Bank Center
Oklahoma City, OK 73102 Pittsburgh, PA 15258
Phone: (405) 231-6853 Phone: (412) 234-4458
Fax: (405) 231-6788 Fax: (412) 234-6375
CURTIS L. ANDERSON MAY SEEMAN
Nations Bank of Texas, N.A. Vice President
Sixty Fourth Floor Bank of America NT&SA (Lender)
901 Main Street 4th Floor - 1850 Gateway
Dallas, TX 75202 Concord, CA 94520
Phone: (214) 508-1290 Phone: (510) 675-7483
Fax: (214) 508-3943 Fax: (510) 603-8208
HAYDEN HYDE DAVID SISLER
Boatmen's First National Bank of Oklahoma Bank of America NT&SA (Agent and Lender)
515 So. Boulder, Lobby Level Three Allen Center, Ste. 4550
Tulsa, OK 74103 333 Clay Street
Phone: (918) 591-8319 Houston, TX 77002
Fax: (918) 591-8209 Phone: (713) 651-4875
Fax: (713) 651-4808
</TABLE>
62
<PAGE> 9
<TABLE>
<S> <C>
DAN TORBETT DAVID W. PITTS
Citizens Bank, Lawton, Oklahoma The Stillwater National Bank & Trust Company
1420 W. Lee Boulevard 608 South Main Street
Lawton, OK 73501 Stillwater, OK 74076
Phone: (405) 250-4145 Phone: (405) 372-2230
Fax: (405) 250-4343 Fax: (405) 377-3808
DAVID KEDY GREG BOUDREAU
WestStar Bank First Southwest Bank of Frederick
100 South East Frank Phillips Blvd. 200 N. Main
Bartlesville, OK 74003 Frederick, OK 73542
Phone: (918) 337-3000 Phone: (405) 335-7522
Fax: (918) 337-3506 Fax: (405) 335-7520
</TABLE>
63
<PAGE> 1
EXHIBIT (24)
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
ONEOK Inc.:
We consent to incorporation by reference in the Registration Statement Nos.
33-04177, 33-04179, and 33-06857 on Form S-8 and Nos. 33-58555 and 33-61637 on
Form S-3 of ONEOK Inc. of our report dated October 10, 1996, relating to the
consolidated balance sheets of ONEOK Inc.and subsidiaries as of August 31, 1996
and 1995, 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, 1996, which report appears in the August 31, 1996 annual report on
Form 10-K of ONEOK Inc. Our report refers to a change in the method of
accounting for the impairment of long-lived assets in 1996.
KPMG Peat Marwick LLP
Tulsa, Oklahoma
October 10, 1996
<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, 1996,
AND THE CONSOLIDATED BALANCE SHEET AT AUGUST 31, 1996, FOR ONEOK INC. AND
SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER>1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1996
<PERIOD-START> SEP-01-1995
<PERIOD-END> AUG-31-1996
<CASH> 598
<SECURITIES> 0
<RECEIVABLES> 119,338
<ALLOWANCES> 0
<INVENTORY> 91,556
<CURRENT-ASSETS> 233,146
<PP&E> 1,336,652
<DEPRECIATION> 541,618
<TOTAL-ASSETS> 1,219,891
<CURRENT-LIABILITIES> 202,630
<BONDS> 0
0
9,000
<COMMON> 207,084
<OTHER-SE> 207,611
<TOTAL-LIABILITY-AND-EQUITY> 1,219,891
<SALES> 0
<TOTAL-REVENUES> 1,224,345
<CGS> 0
<TOTAL-COSTS> 1,103,310
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 35,162
<INCOME-PRETAX> 85,873
<INCOME-TAX> 33,037
<INCOME-CONTINUING> 52,836
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 52,836
<EPS-PRIMARY> 1.93
<EPS-DILUTED> 1.93
</TABLE>
