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
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.
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
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.
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.
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.
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.

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.
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.
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 --------------------------------------------------------------------------- Productive 0.0 2.7 Dry 0.6 1.8 Total 0.6 4.5 =========================================================================== Productive 2.4 6.3 Dry 1.8 1.9 Total 4.2 8.2 =========================================================================== 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
ITEM 3.

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.
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.
ITEM 4.

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.
PART II
ITEM 5.

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:
(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.
ITEM 6.

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.
ITEM 7.

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 a 23.4 percent increase in net income. Higher earnings attributable to the regulated business are the result of reduced costs and increased margins. Growth of the gas marketing operations is attributable to weather related demand and effectively combining gas supply and
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 differing price indices and hedge the price risk to the Company.
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
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)
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.
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
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 ================================================================================
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.
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
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.
ITEM 8.

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.
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
ONEOK Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes to consolidated financial statements.
ONEOK Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
ONEOK Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS
ONEOK Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
ONEOK Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
See accompanying notes to consolidated financial statements.
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. 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.
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.
Maintenance and repairs are charged directly to expense. Generally, the cost of property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of operating units or systems are recognized in income.
PRODUCTION PROPERTY - The Company uses the successful-efforts method to account for costs incurred in the acquisition and exploration of oil and natural gas reserves. Costs to acquire mineral interests in proved reserves, and to drill and equip development wells are capitalized. Geological and geophysical costs and costs to drill exploratory wells which do not find proved reserves are expensed. Unproved
oil and gas properties which are individually significant are periodically assessed for impairment 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 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 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, such loss is included in depreciation, depletion and amortization expense.
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.
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 ================================================================================
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.
(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.
(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 ================================================================================
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.
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.
(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
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.
(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.
(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 ================================================================================
(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 ================================================================================
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:
(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 -- -- - --------------------------------------------------------------------------------
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.

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.

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.

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.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
PART IV
ITEM 14.

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.
(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.
(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.
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.
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)
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 G. R. WILLIAMS - ----------------------------- ----------------------------- W. L. Ford G. R. Williams Director Director
J. M. GRAVES S. L. YOUNG - ----------------------------- ----------------------------- J. M. Graves S. L. Young Director Director
S. J. JATRAS - ----------------------------- S. J. Jatras Director
D. L. KYLE - ----------------------------- D. L. Kyle Director
B. H. MACKIE - ----------------------------- B. H. Mackie Director
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.
(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.
(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.