ITEM 1. BUSINESS
GENERAL
ONEOK, Inc., an Oklahoma corporation, was organized on May 16, 1997. On November 26, 1997, we acquired the natural gas business of Westar Energy, Inc. (Westar), formerly Western Resources, Inc., and merged with ONEOK Inc., a Delaware corporation organized in 1933. We are the successor to the company founded in 1906 known as Oklahoma Natural Gas Company.
We purchase, transport, store and distribute natural gas. We are the largest natural gas distributor in Oklahoma and Kansas and the third largest natural gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers. Our largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services operation is engaged in wholesale and retail natural gas marketing and trading activities and provides services to customers in many states and Canada. We are the sole general partner and own 45.7 percent of ONEOK Partners, L.P. (NYSE: OKS), a publicly traded limited partnership. ONEOK Partners gathers, processes, stores and transports natural gas in the United States and owns a natural gas liquids system that connects much of the NGL supply in the Mid-Continent region with key market centers.
DESCRIPTION OF BUSINESS SEGMENTS
We report operations in the following reportable business segments:
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ONEOK Partners
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Distribution
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Energy Services
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Other
For financial and statistical information regarding our business units by segment, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. See Note M of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of changes in reportable business segments as well as sales to unaffiliated customers, operating income and total assets by business segment.
SIGNIFICANT DEVELOPMENTS IN 2006
In October 2006, we completed the sale of our Spring Creek power plant to Westar. The financial information related to the properties sold in this transaction is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.
In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners. Simultaneously, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines, and we acquired the remaining 17.5 percent of the general partner interests in ONEOK Partners from an affiliate of TransCanada.
Also in April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners, increasing its ownership interest to 100 percent.
Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements due to the adoption of EITF 04-5.
NARRATIVE DESCRIPTION OF BUSINESS
ONEOK Partners
We own approximately 37.0 million common and Class B limited partner units, and the entire 2 percent general partner interest which represents a 45.7 percent interest in ONEOK Partners. We receive distributions from ONEOK Partners on our
common and Class B units, and our 2 percent general partner interest. See Note S of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of our incentive distribution rights.
Business Strategy - ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to its unitholders and to increase its quarterly cash distributions over time. ONEOK Partners’ ability to maintain and grow its distributions to unitholders depends on the growth of its existing businesses and strategic acquisitions.
ONEOK Partners’ focus is on expanding and acquiring assets related to energy transportation, gathering, processing, fractionation, storage and marketing that will utilize its core competencies, minimize commodity price risk and provide immediate cash flow. ONEOK Partners finances its acquisitions and capital expenditures with a mix of operating cash flows, debt and equity.
Segment Description - Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” and we elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are now included in our ONEOK Partners segment and all periods presented have been restated to reflect this change. We own an aggregate 45.7 percent of ONEOK Partners; the remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our Consolidated Statements of Income.
Our ONEOK Partners segment is engaged in the gathering and processing of natural gas and fractionation of NGLs primarily in the Mid-Continent and Rocky Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and Wyoming. These operations include the gathering of natural gas production from crude oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed for removal of water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream. This stream can then be separated by a distillation process, referred to as fractionation, into marketable product components such as ethane, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products can then be stored, transported and marketed to a diverse customer base of end-users. Operating revenue from the gathering and processing business is primarily derived from the following three types of contracts:
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Percent of Proceeds (POP) - ONEOK Partners retains a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas.
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Fee - ONEOK Partners is paid a fee for the services provided such as Btus gathered, compressed and/or processed.
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Keep-Whole - ONEOK Partners extracts NGLs from raw natural gas and returns to the producer volumes of merchantable natural gas containing the same amount of Btus as the raw natural gas that was originally delivered.
Through our acquisition of the natural gas liquids businesses owned by Koch Industries, Inc. (Koch) in July 2005, we acquired facilities that gather, fractionate and treat raw NGLs and store NGL purity products. ONEOK Partners now operates approximately 2,500 miles of FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas. Its natural gas liquids gathering pipelines deliver raw NGLs gathered from natural gas processing plants located in these states to fractionation facilities in Medford, Oklahoma, Hutchinson and Conway, Kansas, and Mont Belvieu, Texas. Its natural gas liquids distribution pipelines move NGL products from Oklahoma and Kansas to the market centers of Conway, Kansas, and Mont Belvieu, Texas.
A large number of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from raw natural gas to meet natural gas pipeline quality specifications, are connected to ONEOK Partners’ natural gas liquids gathering systems. The natural gas liquids operations gather these NGLs and deliver them to ONEOK Partners’ fractionators. The NGLs are then separated into NGL products to realize the greater economic value of the NGL components. The individual NGL products are then stored and/or distributed to petrochemical manufacturers, refineries and propane distributors.
Operating revenue for the natural gas liquids business is primarily derived from:
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Exchange Services - ONEOK Partners gathers and transports raw NGLs to its fractionators, separating them into marketable products and redelivering the purity NGL products to its customers for a fee.
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Optimization and Marketing - ONEOK Partners uses its asset base, portfolio of contracts and market knowledge to capture location and seasonal price spreads through transactions that optimize the flow of its NGL products between the major market centers in Conway, Kansas, and Mont Belvieu, Texas.
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Isomerization - ONEOK Partners converts normal butane to the more valuable iso-butane used by the refining industry to upgrade the octane of motor gasoline.
ONEOK Partners’ pipeline and storage assets gather and transport natural gas through regulated intrastate natural gas transmission pipelines and NGLs through regulated intrastate natural gas liquids gathering and FERC-regulated natural gas liquids gathering and distribution pipelines. ONEOK Partners operates non-processable natural gas gathering systems and natural gas storage facilities in Oklahoma, Kansas and Texas.
ONEOK Partners’ intrastate natural gas pipelines in Oklahoma access the major natural gas producing areas, which allows for natural gas and NGLs to be moved throughout the state. ONEOK Partners has intrastate natural gas pipelines that access the major natural gas producing area in south central Kansas. In Texas, ONEOK Partners’ intrastate pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, providing for natural gas to be moved to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. ONEOK Partners’ regulated natural gas liquids gathering pipelines enable raw NGLs gathered in Oklahoma, Kansas and the Texas panhandle to be delivered to its fractionation facilities and to its natural gas liquids distribution pipelines, which allows access to the two main NGL market centers in Conway, Kansas, and Mont Belvieu, Texas.
The majority of ONEOK Partners’ operating revenue from the pipelines and storage business is derived from fee-based services provided to its natural gas liquids business and our Distribution and Energy Services segments. ONEOK Partners’ transportation contracts for its regulated natural gas and natural gas liquids pipelines are based upon rates stated in its tariffs. Tariffs specify the maximum rates customers can be charged, which can be discounted to meet competition if necessary. In Texas and Kansas, ONEOK Partners’ natural gas storage service is a fee-based business that may be regulated by the state and by the FERC for certain types of services. In Oklahoma, ONEOK Partners’ natural gas gathering and natural gas storage operations are not subject to rate regulation and have market-based rate authority from FERC for certain types of services.
ONEOK Partners’ interstate natural gas pipelines primarily transport natural gas from the Western Canada Sedimentary Basin to the Midwestern United States through Midwestern Gas Transmission, Viking Gas Transmission, Guardian Pipeline and its 50 percent ownership in Northern Border Pipeline. These assets are primarily located in North Central United States and span from Montana to Tennessee.
Operating income from our ONEOK Partners segment was 59.3 percent, 65.5 percent and 43.0 percent of our consolidated operating income from continuing operations in 2006, 2005 and 2004, respectively. Our ONEOK Partners segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for 15 percent, 19 percent and 22 percent of our ONEOK Partners’ segment’s revenues in 2006, 2005 and 2004, respectively.
Market Conditions and Seasonality - ONEOK Partners’ business is affected by the economy, natural gas and NGL price volatility, and weather. The strength of the economy has a direct relationship on manufacturing and industrial companies’ demand for natural gas and NGL products. Volatility in the commodity markets impacts ONEOK Partners’ customers’ decisions relating to the output of the gas processing plants and the injection and withdrawal of natural gas and natural gas liquids in storage. In addition, its intrastate natural gas pipelines and natural gas liquids gathering pipelines are affected by operational or market driven changes in the output of the gas processing plants to which it is connected. Gas processing plant natural gas and NGL output may increase or decrease affecting the volume of natural gas and NGLs shipped through the system as a result of the relative value of natural gas to NGL prices, primarily ethane to natural gas and composite NGL price to natural gas. In addition, volume delivered through the system may increase or decrease as a result of the relative NGL price between the Mid-Continent and Gulf Coast regions. Natural gas transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand.
ONEOK Partners’ natural gas assets primarily serve local distribution companies (LDCs), large industrial companies, municipalities, irrigation customers, power generation facilities and marketing companies. ONEOK Partners natural gas and natural gas liquids pipelines compete directly with other intrastate and interstate pipeline companies. Additionally, ONEOK Partners competes directly with other storage facilities. Competition for natural gas transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition for both natural gas and NGL services are location, market access, natural gas and NGL prices, fees
for services and quality of services provided. ONEOK Partners believes that its pipelines and storage assets enable it to compete effectively.
During 2006, both crude oil and natural gas prices were volatile, with NYMEX crude oil settlement prices ranging from $55.81 to $73.08 per Bbl and NYMEX natural gas settlement prices ranging from $4.20 to $11.43 per MMBtu.
ONEOK Partners is affected by producer drilling activity, which is sensitive to geological success, as well as availability of capital, commodity prices and regulatory control. The Mid-Continent region is currently experiencing a significant upturn in crude oil and natural gas drilling activity. This resurgence in drilling activity has been driven by increased prices for natural gas and crude oil and by long-term projections of continued demand in the U.S. natural gas market. However, ONEOK Partners is exposed to volume risk from a competitive and a production standpoint. ONEOK Partners continues to see declines in certain fields that supply its gathering and processing operations, and the possibility exists that volumetric declines may surpass new gas development from future drilling.
The factors that typically affect ONEOK Partners’ ability to compete for energy supplies are:
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location of natural gas processing plants relative to its gathering pipelines,
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location of its gathering pipelines relative to its competitors,
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location of its fractionation facilities relative to its competitors,
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efficiency, reliability and costs of operations, including fuel and power consumption,
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available fractionation, pipeline and storage capacity, and
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delivery capabilities to move natural gas and NGL products to its highest value locations.
Despite significant consolidation in the recent past, the U.S. midstream industry remains relatively fragmented, and ONEOK Partners faces competition from a variety of companies, including major integrated oil companies, major pipeline companies and their affiliated marketing companies, and national and local natural gas gatherers, processors and marketers. Competition exists for obtaining natural gas supplies for gathering and processing operations. The factors that typically affect ONEOK Partners’ ability to compete are:
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producer drilling activity,
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petrochemical industry’s level of capacity utilization and its specific feedstock requirements,
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fees charged under the contract,
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pressures maintained on the gathering systems,
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location of its gathering systems relative to its competitors,
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location of its gathering systems relative to drilling activity,
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efficiency and reliability of the operations, and
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delivery capabilities that exist in each system and plant location.
ONEOK Partners has responded to these industry conditions by making capital investments to improve plant processing flexibility and reduce operating costs, selling assets in non-core operating areas and renegotiating unprofitable contracts. The principal goal of the contract renegotiation effort is to eliminate unprofitable contracts and improve margins, primarily during periods when the keep-whole spread is negative.
Some of ONEOK Partners’ products, such as natural gas and propane used for heating, are subject to seasonality, resulting in more demand during the months of November through March. As a result, prices of these products are typically higher during that time period. Demand has also increased for natural gas in the summer periods as more electric generation is dependent upon natural gas for fuel. Other products, such as ethane, are tied to the petrochemical industry, while iso-butane and natural gasoline are used by the refining industry as blending stocks. As a result, the prices of these products are affected by the economic conditions and demand associated with these various industries.
The main factors that affect ONEOK Partners’ margins are:
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natural gas liquid transportation and fractionation volumes and associated fees,
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natural gas transportation and storage volumes,
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weather, both temperature and precipitation,
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commodity and regional pricing differences,
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fees charged for processing services and storage services, and
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the Mid-Continent and Rocky Mountain natural gas price, crude oil price and the daily average Oil Price Information Service (OPIS) price for our NGL products sold, as well as the relative value on a Btu basis of each of the components to each other.
Government Regulation - The FERC has traditionally maintained that a processing plant is not a facility for transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act (NGA). Although the FERC has made no specific declaration as to the jurisdictional status of ONEOK Partners’ natural gas processing operations or facilities, ONEOK Partners’ natural gas processing plants are primarily involved in removing NGLs and, therefore, ONEOK Partners believes, it is exempt from FERC jurisdiction. The NGA also exempts natural gas gathering facilities from the jurisdiction of the FERC. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. ONEOK Partners believes its gathering facilities and operations meet the criteria used by the FERC to determine a non-jurisdictional gathering facility status. ONEOK Partners can transport residue gas from its plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act (NGPA).
The states of Oklahoma and Kansas also have statutes regulating, in various degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.
Revenues for ONEOK Partners’ proprietary natural gas liquids pipelines in both Oklahoma and Kansas are not regulated by the FERC or the states’ respective corporation commissions. ONEOK Partners’ fractionation facilities are operated under the regulatory framework and oversight of various governmental agencies. These agencies primarily include the U.S. EPA and its state counterparts, as well as the OSHA. ONEOK Partners has developed systems to identify, control, and manage compliance risks and obligations, including environmental, health and safety management systems.
ONEOK Partners’ natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. ONEOK Partners has flexibility in establishing natural gas transportation rates with customers. However, there is a maximum rate that ONEOK Partners can charge its customers in Oklahoma and Kansas. Its natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas are interstate pipelines regulated by the FERC and by the U.S. Department of Transportation’s Office of Pipeline Safety (OPS). ONEOK Partners transports raw NGLs and NGL products pursuant to filed tariffs.
ONEOK Partners’ pipelines are operated under the guidance and oversight of various governmental agencies. Besides programs mandated by the OSHA, EPA and various state environmental agencies, the OPS as well as the OCC, the KCC and the RRC, have each established a regulatory framework focused on asset integrity, safety and environmental protection.
Distribution
Business Strategy - Our integrated strategy for our local distribution companies incorporates a rates and regulatory plan which includes positive relationships with regulators, consistent strategies and synchronized rate case filings. We focus on growth of our rate base and customer base through prudent investment in our system while focusing on cost control. We provide customer choice programs which reduce volumetric sensitivity and create value for our customers.
Segment Description - Our Distribution segment provides natural gas distribution services to over two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers.
Our operating results are primarily affected by the number of customers, usage and the ability to establish delivery rates that provide an authorized rate of return on our investment and recovery of our cost of service. Natural gas costs are passed through to our customers based on the actual cost of gas purchased by the respective distribution companies. Substantial fluctuations in natural gas sales can occur from year to year without significantly impacting our gross margin, since the fluctuations in natural gas costs affect natural gas sales and cost of gas by an equivalent amount. Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of natural gas is used principally for heating. Accordingly, the volume of natural gas sales is normally higher during the heating season (November through March) than in other months of the year.
Operating income from the Distribution segment was 13.6 percent, 14.3 percent and 24.8 percent of the consolidated operating income from continuing operations in 2006, 2005 and 2004, respectively. Our Distribution segment had no single external customer from which it received 10 percent or more of consolidated revenues. None of our Distribution’s segment revenues were due to intersegment sales.
Natural Gas Supply - The majority of our distribution segment’s natural gas supply is provided under contracts from a number of suppliers. These contracts are awarded through a competitive bid process. The remainder of our distribution
segment’s natural gas supply is purchased from a combination of direct wellhead production, natural gas processing plants, natural gas marketers and production companies.
There is an adequate supply of natural gas available to our utility systems, and we do not anticipate problems with securing additional natural gas supply as needed for our customers. However, if supply shortages occur, Oklahoma Natural Gas’ rate schedule “Order of Curtailment” and Kansas Gas Service’s rate order “Priority of Service” provide for first reducing or totally discontinuing gas service to large industrial users and then requesting that residential and commercial customers reduce their gas requirements to an amount essential for public health and safety. Texas Gas Service’s gas transportation contracts with interruption provisions require large volume users to purchase their natural gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the gas is needed for higher priority customers. In addition, during times of special supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local regulatory agencies.
Market Conditions and Seasonality - Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 86 percent, 71 percent and 14 percent of the distribution markets for Oklahoma, Kansas and Texas, respectively. Natural gas sold to residential and commercial customers, which is used primarily for heating, accounts for approximately 78 and 20 percent of natural gas sales, respectively, in Oklahoma, 62 and 17 percent of natural gas sales, respectively, in Kansas, and 66 and 25 percent of natural gas sales, respectively, in Texas.
A franchise, although nonexclusive, is a utility’s right to use the municipal streets, alleys, and other public ways for a defined period of time in exchange for a fee. In management’s opinion, our franchises contain no unduly burdensome restrictions and are sufficient for the transaction of business in the manner in which it is now conducted.
Under our transportation tariffs, qualifying industrial and commercial customers are able to purchase natural gas from the supplier of their choice and have it transported for a fee by Oklahoma Natural Gas, Kansas Gas Service or Texas Gas Service. Because of increased competition for the transportation of natural gas to commercial and industrial customers, some of these customers may be lost to affiliated or unaffiliated transporters. If our ONEOK Partners segment gained some of this business, it would result in a shift of some revenues from our Distribution segment to our ONEOK Partners segment.
The natural gas industry is expected to remain highly competitive, resulting from initiatives being pursued by the industry and regulatory agencies that allow industrial and commercial customers increased options for energy supplies and service. We believe that we must maintain a competitive advantage in order to retain our customers and, accordingly, we focus on providing reliable, efficient service and reducing costs.
The Distribution segment is subject to competition from other pipelines for our existing industrial load. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service compete for service to the large industrial and commercial customers, and competition continues to lower rates. A portion of transportation services provided by Oklahoma Natural Gas and Kansas Gas Service are at negotiated rates that are generally below the approved transportation tariff rates. Increased competition potentially could lower these rates. In the service area for Texas Gas Service, reduced rate transportation service is negotiated only when a competitive pipeline is in proximity to bypass Texas Gas Service or another energy option is available. Any negotiated transportation service contract is filed under a separate, confidential tariff at the RRC. Industrial and transportation sales volumes tend to remain relatively constant throughout the year.
Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of natural gas is used principally for heating. Accordingly, the volume of natural gas sales is normally higher during the heating season (November through March) than in other months of the year. Tariff rates for Oklahoma Natural Gas, Kansas Gas Service and certain jurisdictions in Texas include a temperature normalization adjustment clause during the heating season, which mitigates the effect of fluctuations in weather. The rate structure for Oklahoma Natural Gas includes billing options for all gas sales customers. Under this rate structure, certain high volume customers pay a higher monthly service charge and a lower per dekatherm delivery charge, while lower usage customers pay a lower monthly service charge coupled with a higher per dekatherm delivery charge. Customers can elect to change billing options to ensure that they are billed under the alternative that best fits their individual usage, but they must remain on the selected option for a full year after the change is made. Additionally, with prior KCC approval, Kansas Gas Service has a natural gas hedging program in place to reduce volatility in the natural gas price paid by consumers. The costs of this program are borne by the Kansas Gas Service customers. Texas Gas Service also has a natural gas hedging program for certain of its jurisdictions. Approximately 90 percent of Texas Gas Service’s revenues are protected from abnormal weather due to a higher customer charge or weather normalization adjustment clauses. Texas Gas Service’s weather normalization adjustment clause applies to 58 Texas towns and cities, including Austin and Galveston, to stabilize earnings and neutralize the impact of unusual weather on customers. A higher customer charge is included in the authorized rate design for the jurisdictions of El Paso, north Texas, Rio Grande Valley and Port Arthur to protect customers from abnormal rate fluctuation due to weather.
Government Regulation - Rates charged for natural gas services are established by the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas Service. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC. Natural gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. Our distribution companies do not make a profit on the cost of gas. Other changes in costs must be recovered through periodic rate adjustments approved by the OCC, KCC, RRC and various municipalities in Texas. See page 42 for a detailed description of our various regulatory initiatives.
Oklahoma Natural Gas has settled all known claims arising out of long-term gas supply contracts containing “take-or-pay” provisions that purport to require us to pay for volumes of natural gas contracted for but not taken. The OCC has authorized recovery of the accumulated settlement costs over a 20-year period expiring in 2014, or approximately $7.0 million annually, through a combination of a surcharge from customers, revenue from transportation under Section 311(a) of the NGPA and other intrastate transportation revenues.
Energy Services
Business Strategy - We create value by providing premium services to our customers by delivering physical and risk-management products and services through our network of contracted gas supply, transportation and storage assets. We optimize our storage and transportation capacity through the daily application of market knowledge and effective risk management.
Segment Description - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease is 86 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current transportation capacity is 1.8 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and Canada. With these contracted assets, our ongoing business strategies include identifying, developing and delivering specialized services and products for value to our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Also, our storage and transportation capacity provides us opportunities to optimize these positions through our application of market knowledge and risk management skills.
We actively manage the commodity price and volatility risk assumed from providing energy risk management services to our customers by executing derivative instruments in accordance with the parameters established in our commodity risk management policy. The derivative instruments consist of over-the-counter financially settled transactions such as forward, swap, and option contracts and NYMEX futures and option contracts.
Our working capital requirements related to our inventory in storage were as high as $582.7 million during 2006, but had decreased to $536.1 million at December 31, 2006. In addition, margin requirements can result in increased working capital requirements. During 2006, our margin requirements with counterparties ranged from zero to $109.5 million.
Operating income from our Energy Services segment was 26.6 percent, 20.7 percent and 31.3 percent of our consolidated operating income from continuing operations in 2006, 2005 and 2004, respectively. Our Energy Services segment had no single external customer from which it received 10 percent or more of consolidated revenues in 2006 or 2005. In 2004, our Energy Services segment had one customer, BP, PLC and affiliates, from which it received $664.4 million, or approximately 11 percent, of consolidated revenues. Six percent of our total revenues in 2006 were intersegment sales, compared with, eight percent in both 2005 and 2004.
Market Conditions and Seasonality - In response to a very competitive marketing environment resulting from deregulation of natural gas markets, our strategy is to concentrate our efforts on providing reliable service during peak demand periods and capture opportunities created by short-term pricing volatility through our leased storage and transportation assets. We focus on building and strengthening supplier and customer relationships to execute our strategy.
Due to seasonality of supply and demand balances, earnings may be higher during the winter months than the summer months. Our Energy Services segment’s margins are subject to fluctuations during the year, primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas and crude oil. Natural gas sales volumes are
typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices that occur during the winter heating months.
Other
Segment Description - The primary companies in our Other segment include ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C. Prior to the consolidation of ONEOK Partners as of January 1, 2006, our general partner and limited partner interests held through Northern Plains, now known as ONEOK Partners GP, were included in the Other segment.
Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a parking garage and lease an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company, L.L.C. subleases excess office space to others and operates our headquarters office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.
Northern Plains, now known as ONEOK Partners GP, was acquired in November 2004, and we accounted for our 2.73 percent interest in Northern Border Partners, now known as ONEOK Partners, following the equity method during 2004 and 2005. Effective January 1, 2006, we were required to consolidate ONEOK Partners in accordance with EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” See “Impact of New Accounting Standards” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation for additional information.
Our Other segment had no single external customer from which it received 10 percent or more of consolidated revenues.
ENVIRONMENTAL MATTERS
We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have commenced remediation on 11 sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, have commenced soil remediation at an additional site, and we expect to commence soil remediation on the other two sites in 2007. We have begun site assessment at the remaining site where no active remediation has occurred.
To date, we have incurred remediation costs of $6.0 million and have accrued an additional $6.0 million related to the sites where we have commenced or will soon commence remediation. The $6.0 million estimate of future remediation costs for these sites is based on our environmental assessments and remediation plans approved to date by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.
EMPLOYEES
We employed 4,536 people at January 31, 2007. At January 31, 2007, Kansas Gas Service employed 760 people who were subject to collective bargaining contracts and we had no other union employees. Effective January 1, 2007, the employees represented by Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada agreed to representation by the United Steelworkers of America. The following table sets forth our contracts with unions at January 31, 2007.
EXECUTIVE OFFICERS
All executive officers are elected at the annual meeting of our Board of Directors and serve for a period of one year or until successors are duly elected. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.
No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
AVAILABLE INFORMATION
You can access financial and other information at our website www.oneok.com. We make available on our website, free of charge, copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports
of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct, Corporate Governance Guidelines, Director Independence Guidelines and Board of Directors committee charters, including the charters of our audit, executive, executive compensation and corporate governance committees, are also available on our website, and we will make available, free of charge, copies of these documents upon request.
ITEM 1A.
ITEM 1A. RISK FACTORS
Our investors should consider the following risks that could affect us and our business. Although we have tried to discuss key factors, please be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report on Form 10-K, including “Forward-Looking Statements and Risk Factors,” which is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.
RISK FACTORS INHERENT IN OUR BUSINESS
Our cash flow depends heavily on the earnings and distributions of ONEOK Partners.
Some of our largest cash-generating assets are our partnership interests in ONEOK Partners. Therefore, our cash flow is heavily dependent upon the ability of ONEOK Partners to make distributions to its partners. A significant decline in ONEOK Partners’ earnings and/or cash distributions would have a corresponding negative impact on us. For information on the risk factors inherent in the business of ONEOK Partners, see the section below entitled “Risk Factors Related to ONEOK Partners’ Business” and the ONEOK Partners 2006 Annual Report on Form 10-K.
Our nonregulated businesses have a higher level of risk than our regulated businesses.
Our nonregulated operations have a higher level of risk than our regulated operations, which include our utility and natural gas transportation businesses. We expect to continue investing in natural gas projects and other related projects, some or all of which may involve nonregulated businesses or assets. These projects could involve risks associated with operational factors, such as competition and dependence on certain suppliers and customers, and financial, economic and political factors, such as rapid and significant changes in commodity prices, the cost and availability of capital and counterparty risk, including the inability of a counterparty, customer or supplier to fulfill a contractual obligation.
Our distribution companies have recorded certain assets that may not be recoverable from their customers.
Accounting policies for our local distribution companies permit certain assets that result from the regulatory process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from the regulator and analysis of recoverability from internal and external legal counsel to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.
Our businesses are subject to market and credit risks.
We are exposed to market and credit risks in all of our operations. To minimize the risk of commodity price fluctuations, we periodically enter into derivative transactions to hedge anticipated purchases and sales of natural gas, NGLs, crude oil, fuel requirements and firm transportation commitments. Interest rate swaps are also used to manage interest rate risk. Currency swaps are used to mitigate unexpected changes that may occur in anticipated revenue streams of our Canadian natural gas sales and purchases driven by currency rate fluctuations. However, financial derivative instrument contracts do not eliminate the risks. Specifically, such risks include commodity price changes, market supply shortages, interest rate changes and counterparty default. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased interest expense.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by customers of our Energy Services segment. The customers of our Energy Services segment are predominantly local distribution companies, industrial customers, natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their credit-worthiness or ability to pay for our services. Although we attempt to obtain adequate security for these risks, if we fail to adequately assess the credit-worthiness of
existing or future customers, unanticipated deterioration in their credit-worthiness and any resulting nonpayment and/or nonperformance could adversely impact results of operations for our Energy Services segment. In addition, if any of our Energy Services segment’s customers filed for bankruptcy protection, we may not be able to recover amounts owed which would negatively impact the results of operations for our Energy Services segment.
Increased competition could have a significant adverse financial impact on us.
The natural gas industry is expected to remain highly competitive, resulting from deregulation and other initiatives being pursued by the industry and regulatory agencies that allow customers increased options for energy supplies and service. The demand for natural gas and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates, weather, economic conditions and service costs. Our ability to compete also depends on a number of other factors, including competition from other pipelines for our existing load, the efficiency, quality and reliability of the services we provide, and competition for throughput for our gathering systems and processing plants.
In the future, we may face additional competition from new entrants to the energy industry as a result of the Energy Policy Act of 2005. This comprehensive legislation signed into law by President Bush in August 2005 has substantially affected the regulation of energy companies. Among the important changes this act implemented was the repeal of the Public Utility Holding Company Act of 1935 (PUHCA), which became effective in February 2006. PUHCA imposed a number of restrictions, including constraints on the structure of companies involved in the retail distribution of natural gas. As a result of the repeal of PUHCA, new competitors may enter the industry.
We cannot predict when we will be subject to other changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows. Although we believe our businesses are positioned to compete effectively in the energy market, there are no assurances that this will be true in the future.
We may not be able to successfully make additional strategic acquisitions or integrate businesses we acquire into our operations.
Our ability to successfully make strategic acquisitions and investments will depend on: (1) the extent to which acquisitions and investment opportunities become available; (2) our success in bidding for the opportunities that do become available; (3) regulatory approval, if required, of the acquisitions on favorable terms; and (4) our access to capital, including our ability to use our equity in acquisitions or investments, and the terms upon which we obtain capital. If we are unable to make strategic investments and acquisitions, we may be unable to grow. If we are unable to successfully integrate new businesses into our operations, we could experience increased costs and losses on our investments.
Any reduction in our credit ratings could materially and adversely affect our business, financial condition, liquidity and results of operations.
Our senior unsecured debt has been assigned a rating by S&P of “BBB” (Stable) and Moody’s of “Baa2” (Stable). We will seek to maintain an investment grade rating through prudent capital management and financing structures. However, we cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if S&P or Moody’s were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which would adversely affect our financial results, and our potential pool of investors and funding sources could decrease. Further, if our short-term ratings were to fall below A-2 (capacity to meet its financial commitment on the obligation is satisfactory) or P-2 (strong ability to repay short-term debt obligations), the current ratings assigned by S&P and Moody’s, respectively, it could significantly limit our access to the commercial paper market. Any such downgrade of our long- or short-term ratings could increase our cost of capital and reduce the availability of capital and, thus, have a material adverse effect on our business, financial condition, liquidity and results of operations. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.
A downgrade in our credit ratings below investment grade would negatively affect the operations of our wholesale marketing business. If our credit ratings fall below investment grade, ratings triggers and/or adequate assurance clauses in many of our financial and wholesale physical contracts would be in effect. A ratings trigger or adequate assurance clause gives a counterparty the right to suspend or terminate the agreement unless margining thresholds are met. The additional increase in capital required to support our wholesale marketing business would negatively impact our ability to compete, as well as our ability to actively manage the risk associated with existing storage and transportation contracts.
We are subject to comprehensive energy regulation by governmental agencies and the recovery of our costs is dependent on regulatory action.
We are subject to comprehensive regulation by several federal, state and municipal utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including customer service and the rates that we can charge customers. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation by the FERC of our storage and interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass costs related to providing energy and other commodities through to our customers. The regulatory environment applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.
We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations.
We are subject to environmental regulations that could be difficult and costly to comply with.
We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations. For further discussion on this topic, see Item 1, “Environmental Matters.”
We are subject to risks that could limit our access to capital, thereby increasing our costs and adversely affecting our results of operations.
We have grown rapidly in the last several years as a result of acquisitions. Further acquisitions may require additional external capital. If we are not able to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through acquisitions of complementary assets or businesses, will be adversely affected. A number of factors could adversely affect our ability to access capital, including: (1) general economic conditions; (2) capital market conditions; (3) market prices for natural gas, NGLs and other hydrocarbons; (4) the overall health of the energy and related industries; (5) our ability to maintain our investment-grade credit ratings; and (6) our capital structure. Much of our business is capital intensive, and achievement of our long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.
Our business could be adversely affected by strikes or work stoppages by our unionized employees.
As of January 31, 2007, 760 of our 4,536 employees were represented by labor unions under collective bargaining agreements. We are involved periodically in discussions with labor unions representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial condition and results of operations or whether we will be able to reach any agreement with the unions. Any failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending on the operations and the length of the work stoppage, have a material adverse effect on our business, financial condition and results of operations.
We do not fully hedge against price changes in commodities. This could result in decreased revenues and increased costs, thereby resulting in lower margins and adversely affecting our results of operations.
Our nonregulated businesses are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs, crude oil and power prices. Market risk refers to the risk of loss of cash flows and future earnings arising from adverse changes in commodity energy prices. Our primary exposure arises from fixed-price physical purchase or sale agreements that extend for periods of up to five years, natural gas in storage utilized by our Energy Services segment, commodity prices with respect to ONEOK Partners’ POP processing contracts and the difference between natural gas and NGL prices with respect to ONEOK Partners’ keep-whole processing agreements. ONEOK Partners and our Energy Services segment are also exposed to the risk of changing prices or the cost of transportation resulting from purchasing natural gas or NGLs at one location and selling it at another (referred to as basis risk). To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchases and sales of natural gas, NGLs and crude oil. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor our market risk exposure. However, we do not fully hedge against commodity price changes, and therefore, we retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs.
Our Distribution segment uses storage to minimize the volatility of natural gas costs for our customers by storing natural gas in periods of low demand for consumption in peak demand periods. In addition, various natural gas supply contracts allow us the option to convert index-based purchases to fixed prices. Also, we use derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect Kansas Gas Services’ customers from upward volatility in the market price of natural gas. Texas Gas Service also has a natural gas hedging program for certain of its jurisdictions.
Although we control ONEOK Partners, we may have conflicts of interest with ONEOK Partners which could subject us to claims that we have breached our fiduciary duty to ONEOK Partners and its unitholders.
We own 100 percent of the general partner interest and a 43.7 percent limited partner interest in ONEOK Partners. Conflicts of interest may arise between us and ONEOK Partners and its unitholders. In resolving these conflicts, we may favor our own interests and the interests of our affiliates over the interests of ONEOK Partners and its unitholders as long as the resolution does not conflict with the ONEOK Partners’ partnership agreement or our fiduciary duties to ONEOK Partners.
RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS
The volatility of natural gas and NGL prices could adversely affect ONEOK Partners’ cash flow.
A significant portion of ONEOK Partners’ natural gas gathering and processing revenue is derived from the sale of commodities received as payment for its gathering and processing services. Additionally, certain of ONEOK Partners’ gas gathering and processing assets in Oklahoma and Kansas have keep-whole processing contracts, under which ONEOK Partners extracts NGLs and returns to the producer volumes of merchantable natural gas containing the same amount of Btus that were removed as NGLs. This type of contract exposes ONEOK Partners to the keep-whole spread, or gross processing spread, which is the relative difference in the prices of natural gas and NGLs on a Btu basis. As a result, ONEOK Partners is sensitive to natural gas and NGL price fluctuations. Natural gas and NGL prices have been and are likely to continue to be volatile in the future. High natural gas and NGL prices and processing spreads may not continue and could drop precipitously in a short period of time. The prices of natural gas and NGLs are subject to wide fluctuations in response to a variety of factors beyond ONEOK Partners’ control, including the following:
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relatively minor changes in the supply of, and demand for, domestic and foreign natural gas and NGLs;
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market uncertainty;
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the availability and cost of transportation capacity;
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the level of consumer product demand;
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geopolitical conditions impacting supply and demand for natural gas and crude oil;
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weather conditions;
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domestic and foreign governmental regulations and taxes;
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the price and availability of alternative fuels;
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speculation in the commodity futures markets;
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overall domestic and global economic conditions;
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the price of natural gas and NGL imports; and
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the effect of worldwide energy conservation measures.
These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of natural gas and NGLs. As natural gas and NGL prices decline, ONEOK Partners is paid less for its commodities, thereby reducing its cash flow. In addition, production and related volumes could also decline.
ONEOK Partners’ inability to execute growth and development projects and acquire new assets could reduce cash distributions to unitholders.
ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to unitholders and to increase quarterly cash distributions over time. ONEOK Partners’ ability to maintain and grow its distributions to unitholders depends on the growth of its existing businesses and strategic acquisitions. Accordingly, if ONEOK Partners is unable to implement business development opportunities and finance such activities on economically acceptable terms, future growth will be limited, which could adversely impact the results of operations.
ONEOK Partners does not fully hedge against price changes in commodities. This could result in decreased revenues, increased costs and lower margins, thereby adversely affecting the results of ONEOK Partners’ operations.
The ONEOK Partners businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs, crude oil and power prices. Market risk refers to the risk of loss arising from adverse changes in commodity energy prices. ONEOK Partners’ primary exposure arises from the difference between natural gas and NGL prices with respect to its keep-whole processing agreements, commodity prices with respect to its POP processing agreements, and the differential between the individual NGL purity products and NGLs in storage utilized by its natural gas liquids operations. To manage the risk from market fluctuations in natural gas, NGL and condensate prices, ONEOK Partners uses commodity derivative instruments such as futures contracts, swaps and options. However, it does not fully hedge against commodity price changes, and it therefore retains some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs for ONEOK Partners.
If the level of drilling and production in the Mid-Continent, Rocky Mountain and Gulf Coast regions substantially declines, ONEOK Partners’ volumes and revenue could decline.
ONEOK Partners’ ability to maintain or expand its businesses depends largely on the level of drilling and production in the Mid-Continent, Rocky Mountain and Gulf Coast regions. Drilling and production are impacted by factors beyond ONEOK Partners’ control, including:
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demand for natural gas and refinery-grade crude oil;
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producers’ desire and ability to obtain necessary permits in a timely and economic manner;
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natural gas field characteristics and production performance;
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surface access and infrastructure issues; and
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capacity constraints on natural gas, crude oil and natural gas liquids pipelines from the producing areas and ONEOK Partners’ facilities.
In addition, drilling and production are impacted by environmental regulations governing water discharge. If the level of drilling and production in any of these regions substantially declines, ONEOK Partners’ volumes and revenue could be reduced.
Pipeline integrity programs and repairs may impose significant costs and liabilities.
In December 2003, the United States Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause ONEOK Partners to incur significant capital and operating expenditures to make repairs or take remediation, preventive or mitigating actions that are determined to be necessary.
Growing ONEOK Partners’ business by constructing new pipelines and new processing and treating facilities or making modifications to its existing facilities subjects ONEOK Partners to construction risks and risks that adequate natural gas or NGL supplies will not be available upon completion of the facilities.
One of the ways ONEOK Partners intends to grow its business is through the construction of additions and modifications to its existing pipeline systems, plants and fractionators and construction of new pipelines and new gathering, processing and treatment facilities. The construction and modification of pipelines and gathering, processing, fractionation and treatment facilities requires the expenditure of significant amounts of capital, which may exceed ONEOK Partners’ expectations, and involves numerous regulatory, environmental, political and legal uncertainties. Construction projects in ONEOK Partners’ industry may increase demand on labor and material which may in turn impact costs and schedule. If ONEOK Partners undertakes these projects, it may not be able to complete them on schedule or at the budgeted cost. Additionally, ONEOK Partners’ revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if ONEOK Partners builds a new pipeline, the construction will occur over an extended period of time, and ONEOK Partners will not receive any material increases in revenues until after completion of the project. ONEOK Partners may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Additionally, ONEOK Partners may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. ONEOK Partners may also rely on estimates of proved reserves in ONEOK Partners’ decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve ONEOK Partners’ expected investment return, which could adversely affect ONEOK Partners’ results of operations and financial condition.
If production from the Western Canada Sedimentary Basin remains flat or declines and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for ONEOK Partners’ transportation services could significantly decrease.
ONEOK Partners depends on natural gas supply from the Western Canada Sedimentary Basin because ONEOK Partners’ interstate natural gas pipelines segment transports primarily Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S. market area. If demand for natural gas increases in Canada or other markets not served by ONEOK Partners’ pipelines and production remains flat or declines, demand for transportation service on ONEOK Partners’ interstate natural gas pipelines could decrease significantly, which could adversely impact ONEOK Partners’ results of operations.
ONEOK Partners’ regulated natural gas pipelines’ transportation rates are subject to review and possible adjustment by federal regulators.
ONEOK Partners’ regulated pipelines are subject to extensive regulation by the FERC and state regulatory agencies, which regulates most aspects of ONEOK Partners’ pipeline business, including ONEOK Partners’ transportation rates. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. Under Northern Border Pipeline’s 2006 rate case settlement, there is a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging Northern Border Pipeline’s rates, and a requirement that Northern Border Pipeline file a rate case within six years.
In the competition for customers, ONEOK Partners may have significant levels of uncontracted or discounted transportation capacity on its natural gas pipelines.
ONEOK Partners’ pipeline and storage and interstate natural gas pipelines businesses compete with other pipelines for natural gas supplies delivered to the markets it serves. As a result of competition, ONEOK Partners may have significant levels of uncontracted or discounted capacity on its pipelines, which could adversely impact ONEOK Partners’ results of operations.
ONEOK Partners’ interstate natural gas pipelines have recorded certain assets that may not be recoverable from its customers.
Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on the ONEOK Partners balance sheet that could not be recorded under GAAP for nonregulated entities. ONEOK Partners considers factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If ONEOK Partners determines future recovery is no longer probable, ONEOK Partners would be required to write off the regulatory assets at that time.
The composition of natural gas received by ONEOK Partners’ pipelines could reduce ONEOK Partners’ available transportation capacity and increase its operating expenses.
If the energy content of the natural gas received by ONEOK Partners’ pipelines is below the energy equivalent specified under ONEOK Partners’ transportation contracts, ONEOK Partners must transport additional natural gas to meet its contractual commitments. The transportation of this additional natural gas reduces the available transportation capacity on ONEOK Partners’ pipelines and could negatively impact ONEOK Partners’ operating revenue.
ONEOK Partners’ operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose it to significant costs and liabilities.
The risk of incurring substantial environmental costs and liabilities is inherent in ONEOK Partners’ operations. ONEOK Partners’ operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:
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the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
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the federal Clean Water Act and analogous state laws that regulate discharge of wastewaters from ONEOK Partners’ facilities to state and federal waters;
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the federal Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by ONEOK Partners or locations to which ONEOK Partners has sent waste for disposal; and
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the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from ONEOK Partners’ facilities.
Various governmental authorities, including the United States EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs and liabilities in ONEOK Partners’ business due to its handling of the products it gathers, transports and processes, air emissions related to its operations, historical industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which ONEOK Partners’ pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from ONEOK Partners’ operations. Some sites ONEOK Partners operates are located near current or former third-party hydrocarbon storage and processing operations and there is a risk that contamination has migrated from those sites to ONEOK Partners’ sites. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase ONEOK Partners’ compliance costs and the cost of any remediation that may become necessary, some of which may be material.
ONEOK Partners’ insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against ONEOK Partners. ONEOK Partners’ business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might also adversely affect ONEOK Partners’ products and activities and federal and state agencies could impose additional safety requirements, all of which could materially affect ONEOK Partners’ profitability.
ONEOK Partners is exposed to the credit risk of its customers and its credit risk management may not be adequate to protect against such risk.
ONEOK Partners is subject to the risk of loss resulting from nonpayment and/or nonperformance by ONEOK Partners’ customers. ONEOK Partners’ customers are predominantly natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their credit-worthiness or ability to pay ONEOK Partners for its services. ONEOK Partners has obtained the maximum security allowed under the FERC credit-worthiness policy for its FERC-regulated assets. If ONEOK Partners fails to adequately assess the credit-worthiness of existing or future customers, unanticipated deterioration in their credit-worthiness and any resulting nonpayment and/or nonperformance could adversely impact ONEOK Partners’ results of operations. In addition, if any of ONEOK Partners’ customers filed for bankruptcy protection, it may not be able to recover amounts owed
or resell the capacity held by such customer, which would negatively impact ONEOK Partners’ results of operations.
Any reduction in the ONEOK Partners credit ratings could materially and adversely affect its business, financial condition, liquidity and results of operations.
ONEOK Partners’ senior unsecured debt has been assigned a rating by Moody’s of “Baa2” (Stable), by S&P of “BBB” (Stable) and by Fitch of “BBB” (Stable). ONEOK Partners will seek to maintain an investment grade rating through prudent capital management and financing structures. However, ONEOK Partners cannot provide assurance that any of its current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if Moody’s and S&P were to downgrade ONEOK Partners’ long-term rating, particularly below investment grade, its borrowing costs would increase, which would adversely affect its financial results, and its potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold ONEOK Partners’ securities. Each rating should be evaluated independently of any other rating.
ONEOK Partners’ use of financial instruments to hedge market risk may result in reduced income.
ONEOK Partners utilizes financial instruments to mitigate its exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce its exposure to interest rate fluctuations could expose it to risk of financial loss where it has contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit ONEOK Partners would otherwise receive if it has contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate. Hedging arrangements that are used to reduce ONEOK Partners’ exposure to commodity price fluctuations may limit the benefit ONEOK Partners would otherwise receive if market prices for natural gas and NGLs exceed the stated price in the hedge instrument for these commodities.
ONEOK Partners’ inability to execute growth and development projects related to its interstate pipelines and acquire new assets could reduce cash distributions to its unitholders.
ONEOK Partners’ interstate natural gas pipelines are generally allowed to collect a return on its assets’ recorded book value, generally referred to as rate base, in its transportation rates. ONEOK Partners’ interstate pipelines must maintain or increase the book value of its assets through growth projects in order to maintain or increase the return collected on ONEOK Partners’ rate base. Accordingly, if ONEOK Partners is unable to implement business development opportunities and finance such activities on economically acceptable terms, ONEOK Partners’ future growth will be limited, which could adversely impact its results of operations.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES
DESCRIPTION OF PROPERTIES
ONEOK Partners
Our ONEOK Partners segment property consists of the following:
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approximately 14,600 miles of raw natural gas gathering pipelines with capacity owned, leased or contracted for in the Mid-Continent and Rocky Mountain regions;
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14 active gas processing plants with approximately 1.7 Bcf/d of owned, leased or contracted processing capacity in the Mid-Continent and Rocky Mountain regions;
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approximately 100 MBbl/d of owned, leased or contracted fractionation capacity at our gas processing plants in the Mid-Continent and Rocky Mountain regions;
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approximately 1,950 miles of natural gas liquids gathering pipelines;
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approximately 160 miles of natural gas liquids distribution pipelines;
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interest in four natural gas liquids fractionators with proportional operating capacity of approximately 379 MBbl/d;
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one 9 MBbls/d isomerization unit;
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seven owned or leased NGL storage facilities with operating storage capacity of approximately 24.6 million barrels;
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approximately 5,700 miles of intrastate natural gas gathering and regulated intrastate transmission pipelines with peak transportation capacity of approximately 2.9 Bcf/d;
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approximately 2,400 miles of FERC-regulated natural gas liquids gathering and distribution pipelines with peak transportation capacity of approximately 355 MBbl/d;
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11 underground natural gas storage facilities in Oklahoma, Kansas and Texas with active working gas capacity of approximately 51.6 Bcf;
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approximately 1,300 miles of FERC-regulated natural gas transmission pipeline with peak transportation capacity of approximately 2.0 Bcf/d; and
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50 percent interest in Northern Border Pipeline.
Distribution
We own approximately 17,850 miles of pipeline and other distribution facilities in Oklahoma, approximately 13,300 miles of pipeline and other distribution facilities in Kansas and approximately 9,100 miles of pipeline and other distribution facilities in Texas. We own a number of warehouses, garages, meter and regulator houses, service buildings and other buildings throughout Oklahoma, Kansas and Texas. We also own or lease a fleet of vehicles and maintain an inventory of spare parts, equipment and supplies.
Energy Services
Our total storage capacity under lease is 86 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current transportation capacity is 1.8 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. Our storage leases are spread across 18 different facilities in seven states and one facility in Canada, allowing us the flexibility to capture volatility in the energy markets.
Other
We own a parking garage and land, subject to a long-term ground lease. Located on this land is a seventeen-story office building with approximately 517,000 square feet of net rentable space. We also lease our office building under a lease term that expires in 2009 with six five-year renewal options. After the primary term or any renewal period, we can purchase the property at its fair market value. We occupy approximately 228,000 square feet for our own use and sublease the remaining space to others.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. We, along with two of our subsidiaries and our Oklahoma Natural Gas division, were served on June 21, 1999, as defendants in an action brought under the False Claims Act by Mr. Grynberg, ostensibly on behalf of the United States. Approximately 70 other substantially identical lawsuits were filed against other companies in the natural gas industry. The main claim against the defendants alleges that they intentionally provided false information to the government concerning the volume and heating content of natural gas produced from lands in which the Federal Government or Native Americans owned the royalty rights. Grynberg seeks to recover $5,000 to $10,000 for each violation of the False Claims Act, as well as treble damages for any underpayment. The actions brought by Grynberg were transferred to the United States District Court for the District of Wyoming for coordination of pretrial proceedings. That Court overruled the defendants’ initial motion to dismiss, but granted the motion of the United States to dismiss certain portions of the complaints. On June 4, 2004, we joined with the numerous other defendants in filing a motion to dismiss, contending that Grynberg had not satisfied the unique jurisdictional prerequisites for maintaining an action under the False Claims Act. That motion to dismiss was heard by the Special Master on March 17 and 18, 2005. The Special Master issued his Report and Recommendation on May 16, 2005, recommending in part that all claims against us be dismissed. On October 20, 2006, the Court entered an order affirming in relevant part the Special Master’s recommendation that all claims against us, our subsidiaries, and our Oklahoma Natural Gas division be dismissed. On November 16, 2006, Mr.Grynberg filed his notice of appeal with the United States Court of Appeals for the Tenth Circuit, appealing the Court’s order. The appeal is pending before the Tenth Circuit.
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”). Plaintiffs brought suit on May 28, 1999, against us, five of our subsidiaries and one of our divisions, as well as approximately 225 other defendants. Additionally, in connection with the completion of our acquisition of the natural gas liquids businesses owned by several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.), which is also one of the defendants in this case. Plaintiffs sought class certification for its claims for monetary damages that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the Court refused to certify the class sought by plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to undermeasurement of volumes. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.
Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”). This action was filed by the plaintiffs on May 12, 2003, after the Court had denied class status in Price I. Plaintiffs are seeking monetary damages based upon a claim that 21 groups of defendants, including us and four of our subsidiaries, intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Additionally, in connection with the completion of our acquisition of the natural gas liquids businesses owned by several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.) which is also one of the defendants in this case. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.
In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Kansas Department of Health and Environment. On July 23, 2002, the Division of Environment of the Kansas Department of Health and Environment (KDHE) issued an administrative order that assessed a $180,000 civil penalty against us. The penalty was based upon allegations of violations of various KDHE regulations relating to our operation of hydrocarbon storage wells, monitoring requirements applicable to stored hydrocarbon products, and spill reporting in connection with the gas explosion at our Yaggy gas storage facility in Hutchinson, Kansas, in January 2001. In addition, the order required us to monitor existing unplugged vent wells, drill additional observation, monitoring and vent wells as directed by the KDHE, perform cleanup activities relating to certain brine wells, and prepare a geoengineering plan with respect to the Yaggy gas field. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. Remediation required under the consent order has been completed. Monitoring of the wells and review of the data for the geoengineering study is ongoing.
Loyd Smith, et al v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 01-C-0029, in the District Court of Reno County, Kansas, and Gilley et al. v. Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation L.L.C. and Mid Continent Market Center, Inc., Case No. 01-C-0057, in the District Court of Reno County, Kansas. Two separate class action lawsuits were filed against us and several of our subsidiaries in early 2001 relating to certain gas explosions in Hutchinson, Kansas. The court certified two separate classes of claimants, which included all owners of residential real estate in Reno County, Kansas whose property had allegedly declined in value, and owners of businesses in Reno County whose income had allegedly suffered. Both cases were adjudicated in September 2004 and resulted in jury verdicts. In the class action relating to the residential claimants, the jury awarded $5 million in actual damages, which is covered by insurance. In the business owners’ class action, the jury rendered a defense verdict awarding no actual damages. The jury rejected claims for punitive damages in both cases. In a separate hearing on Plaintiffs’ attorney fees, the Judge awarded $2,047,406 in fees and $646,090.78 in expenses, which is also covered by insurance. With the exception of a related lawsuit that was filed in Sedgwick County, Kansas, which is now on appeal (see Note K of Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K for additional discussion on this matter), all other litigation regarding the gas explosions has been resolved. On April 11, 2005, the court denied plaintiffs’ motion for a new trial and denied a post-trial motion filed by defendants. The business-class plaintiffs and residential-class plaintiffs filed notices of appeal. We have filed a notice of appeal of the residential class action verdict and the attorney fee award. The cases were transferred to the Kansas Supreme Court for the appeals, and the appeals have been fully briefed. A ruling on the appeals is pending.
Richard Manson v. Northern Plains Natural Gas Company, LLC, et. al., Civil Action No. 1973-N, in the Court of Chancery of the State of Delaware in and for New Castle County. On March 2, 2006, a holder of limited partnership units of Northern Border Partners, L.P. (“Northern Border”), now ONEOK Partners, filed a class action and derivative complaint on behalf of a putative class of all holders of Northern Border limited partnership units against Northern Border, TransCanada Corporation, us and some of our affiliates, and the individual members of the Policy Committee of Northern Border. On December 1, 2006, a Stipulation of Settlement was filed with the Court. The principal terms of the settlement are: (1) a reduction in the distribution premium on ONEOK-owned units from 115 percent to 110 percent if the vote on the unit conversion and partnership amendment fail; (2) a reduction of the distribution premium on ONEOK-owned units from 125 percent to 123.5 percent if the vote on the unit conversions and partnership amendment fail and ONEOK or its subsidiary is later removed as general partner; and (3) the defendants would not object to an attorney fee award of $2,500,000 or less and expenses of not more than $50,000. Notice of the settlement was mailed to the common unit holders of ONEOK Partners on December 4, 2006. The fairness hearing on the settlement was held on January 18, 2007, in Georgetown, Delaware pursuant to which the Chancery Court entered an Order and Final Judgment approving the settlement and awarding plaintiff’s attorney a $2,500,000 attorney fee and up to $50,000 in costs. ONEOK Partners’ share of the attorney fees and costs is $375,000, with the balance being paid by insurance.
In the Matter of the Application of Kansas Gas Service, a division of ONEOK, Inc., for Adjustment of its Natural Gas Rates in the State of Kansas, Docket No. 06-KGSG-1209-RTS, before the Kansas Corporation Commission. On May 15, 2006, Kansas Gas Service filed a rate case with the Kansas Corporation Commission (KCC) for a $73.3 million annual revenue increase. Kansas Gas Service requested a Return on Equity of 11.25 percent and an overall Rate of Return of 8.87 percent. On November 17, 2006, the KCC approved a settlement that increased utility revenue for Kansas Gas Service by $52.0 million. The settlement will allow Kansas Gas Service’s annual operating income to increase by approximately $44 to $47 million in 2007. The decision adopted a settlement agreement reached among all the parties on October 26, 2006. The decision also allowed Kansas Gas Service to make effective new residential and commercial rates for service rendered on and after January 1, 2007.
Gas Index Pricing Litigation: We, ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending against the following lawsuits that claim damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others: Samuel P. Leggett, et al. v. Duke Energy Corporation, et al. (filed in the Chancery Court for the Twenty-Fifth Judicial District at Somerville, Tennessee, in January 2005); Sinclair Oil Corporation v. ONEOK Energy Services Corporation, L.P., et al. (filed in the United States District Court for the District of Wyoming in September 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); J.P. Morgan Trust Company v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte County, Kansas, in October 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Learjet, Inc., et al. v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte, Kansas, in November 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., et al. (filed in the District Court of Denver County, Colorado, in May 2006, transferred to MDL-1566 in the United States District Court for the District of Nevada); Missouri Public Service Commission v. ONEOK, Inc., et al. (filed in the Sixth Judicial Circuit Court of Jackson County, Missouri, in October 2006, removed to the United States District Court for the Western District Court of Missouri); Arandell Corporation, et al. v. Xcel Energy, Inc., et al. (filed in the Circuit Court for Dane County, Wisconsin, in December 2006, removed to the United States District Court for the Western District of Wisconsin). In each of these lawsuits, the plaintiffs allege that we, OESC and one other affiliate and approximately 10 other energy companies and their affiliates engaged in an illegal scheme to inflate natural gas prices by providing false information to gas price index publications. All of the complaints rely on the U.S. Commodity Futures Trading Commission investigation into and reports concerning false gas price index-reporting or manipulation in the energy marketing industry. Other than as noted below, each of the cases are still in preliminary pretrial proceedings primarily involving the filing of motions to dismiss.
Motions to dismiss have been granted in the Leggett, Sinclair, and J.P. Morgan cases. The dismissal of the Sinclair case has been appealed by the plaintiff to the United States Court of Appeals for the Ninth Circuit. The orders of dismissal in the J.P. Morgan and Leggett cases are still subject to the filing of post-judgment motions or appeals. We continue to analyze all of these claims and are vigorously defending against them.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of our security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report.
PART II.
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION AND HOLDERS
Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in newspaper stock listings. The following table sets forth the high and low closing prices of our common stock for the periods indicated.
There were 15,255 holders of record of our common stock at January 31, 2007.
DIVIDENDS
The following table sets forth the quarterly dividends paid per share of our common stock during the periods indicated.
A quarterly dividend of $0.34 per share was declared in January 2007, payable in the first quarter of 2007.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2006.
(1) Includes stock options, restricted stock incentive units and performance unit awards granted under our Long-Term Incentive Plan and Equity Compensation Plan. For a brief description of the material features of this plan, see Note P of the Notes to Consolidated Financial Statements. Column (c) also includes 128,774, 625,901 and 990,205 shares available for future issuance under our Thrift Plan, Employee Stock Purchase Plan and Profit Sharing Plan, respectively.
(2) Includes our Employee Non-Qualified Deferred Compensation Plan, Deferred Compensation Plan for Non-Employee Directors, and Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note P of the Notes to Consolidated Financial Statements. Column (c) also includes 103,137 shares available for future issuance under the Employee Stock Award Program described below.
(3) Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Non-Employee Directors is distributed to participants at fair market value on the date of distribution. The price used for these plans to calculate the weighted-average exercise price in the table is $43.12, which represents the year-end closing price of our common stock.
(4) Securities reserved for future issuance under our Deferred Compensation Plan for Non-Employee Directors are included in shares reserved for issuance under our Long-Term Incentive Plan, which is reflected in the table as an equity compensation plan approved by security holders.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of our common stock for the periods shown.
(1) Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
94,033 shares for the period October 1-31, 2006
2,745 shares for the period November 1-30, 2006
23,084 shares for the period December 1-31, 2006
(2) Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
210 shares for the period October 1-31, 2006
75 shares for the period November 1-30, 2006
365 shares for the period December 1-31, 2006
EMPLOYEE STOCK AWARD PROGRAM
Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $26 per share, and we have issued and will continue to issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. The total number of shares of our common stock available for issuance under this program is 200,000.
Through December 31, 2006, a total of 86,120 shares had been issued to employees under this program. The following table sets forth information on the number of shares issued during the three months ended December 31, 2006.
The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (1933 Act) in reliance upon SEC releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.
PERFORMANCE GRAPH
The following performance graph compares the performance of our common stock with the S&P 500 Index and the S&P Utilities Index during the period beginning on December 31, 2001, and ending on December 31, 2006. The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.
Value of $100 Investment Assuming Reinvestment of Dividends
At December 31, 2001, and at the End of Every Year Through December 31, 2006
Among ONEOK, Inc., The S&P 500 Index and The S&P Utilities Index
(a) - The Standard & Poors Utilities Index is comprised of the following companies: AES Corp.; Allegheny Energy, Inc.; Ameren Corp.; American Electric Power; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Constellation Energy Group; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Dynegy, Inc.; Edison Int’l.; Entergy Corp.; Exelen Corp.; FirstEnergy Corp.; FPL Group; FPL Group, Inc.; KeySpan Corp.; Nicor, Inc.; NiSource, Inc.; Peoples Energy Corp.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress Energy, Inc., Public Service Enterprise Group; Questar Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; TXU Corp.; and Xcel Energy, Inc.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the periods indicated.
(a) - Through February 5, 2003, we computed our earnings per share in accordance with EITF Topic No. D-95, “Effect of Participating Convertible Securities on the Computation of Basic Earnings per Share,” which was subsequently superseded by EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128.” The dilutive effect of our Series A Convertible Preferred Stock (Series A) was considered in the computation of basic earnings per share utilizing the “if-converted” method for 2003 and 2002. Under the “if-converted” method, the dilutive effect of our Series A on earnings per share could not be less than the amount that would have resulted from the application of the “two-class” method of computing earnings per share. The “two-class” method is an earnings allocation formula that determined earnings per share for our common stock and our participating Series A according to dividends declared and participating rights in the undistributed earnings. Our Series A was a participating instrument with our common stock with respect to the payment of dividends. For the period from January 1, 2003 to February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, earnings per share for this period reflects this further dilution. As a result of our repurchase and exchange of our Series A in February 2003, we no longer applied the provisions of Topic D-95 to our earnings per share computations beginning in February 2003.
See discussion of acquisitions, dispositions and changes in consolidation beginning on page 30 under “Significant Acquisitions And Divestitures” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
EXECUTIVE SUMMARY
The following discussion highlights some of our achievements and significant issues affecting us this past year. Please refer to the Financial and Operating Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Financial Statements for a complete explanation of the following items.
Diluted earnings per share of common stock from continuing operations (EPS) decreased to $2.68 in 2006 from $3.73 in 2005. Excluding the gain on sale of a 20 percent partnership interest in Northern Border Pipeline in 2006 and excluding the 2005 gain on sale of our Texas gathering and processing assets, EPS from continuing operations decreased to $2.40 in 2006, compared with $2.53 in 2005. During 2006, we increased our dividends twice to a current annual dividend of $1.28 per share of common stock. This follows five increases in our dividends during 2005 and 2004. During the first quarter of 2007, we increased our dividend to $0.34 per share of common stock ($1.36 per share on an annualized basis).
ONEOK Partners declared an increase in its cash distribution to $0.98 per unit ($3.92 per unit on an annualized basis) in January 2007, an increase of approximately 23 percent over the $0.80 paid in the first quarter of 2006.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. We also purchased the remaining 17.5 percent
general partner interest, which increased our general partner interest to the entire 2 percent general partner interest in ONEOK Partners. Prior periods have been restated to show our former gathering and processing, natural gas liquids, and pipelines and storage segments as part of our newly formed ONEOK Partners segment. The legacy operations of ONEOK Partners accounted for the 2006 operating income increases in our ONEOK Partners segment since we consolidated ONEOK Partners beginning January 1, 2006, in accordance with EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” See “Impact of New Accounting Standards” beginning on page 31 for additional information on the consolidation of ONEOK Partners. In addition, the acquisition of the natural gas liquids businesses owned by Koch in July 2005, contributed to operating income increases in our ONEOK Partners segment. Our legacy operations in the ONEOK Partners segment benefited from strong commodity prices, wider gross processing spreads and increased natural gas transportation revenues. These increases were slightly offset by decreases in our ONEOK Partners segment resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
In 2006, operating income increased to $861.6 million from $799.0 million in 2005, an 8 percent increase. Our income from continuing operations decreased to $306.7 million in 2006 from $403.1 million in 2005.
Operating income for our Energy Services segment increased $63.6 million for 2006, primarily due to the effect of improved natural gas basis differentials on transportation contracts.
SIGNIFICANT ACQUISITIONS AND DIVESTITURES
In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction and will operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $216 million excluding AFUDC to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and federal regulatory authorities.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own approximately 37.0 million common and Class B limited partner units and the entire 2 percent ONEOK Partners’ general partner interest and control of the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent.
The sale of certain assets comprising our former gathering and processing, pipelines and storage, and natural gas liquids segments did not affect our consolidated operating income on our Consolidated Statements of Income or total assets on our Consolidated Balance Sheets, as we were already required under EITF 04-5 to consolidate our investment in ONEOK Partners effective January 1, 2006. However, minority interest expense and net income are affected. See “Impact of New Accounting Standards” beginning on page 31 for additional discussion of EITF 04-5.
In connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada
becoming operator of the pipeline in April 2007. Beginning January 1, 2006, Northern Border Pipeline is accounted for as an investment under the equity method. TransCanada paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.
Also in April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was retroactive to January 1, 2006.
In December 2005, we sold our natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $527.2 million and recorded a pre-tax gain of $264.2 million, which is included in gain on sale of assets in our ONEOK Partners segment’s operating income. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. We used the net cash proceeds from this sale to prepay our 7.75 percent $300.0 million long-term debt that was due in August 2006.
In October 2005, we entered into an agreement to sell our Spring Creek power plant, located in Oklahoma, to Westar for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The financial information related to the properties sold is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.
In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. The financial information related to the properties sold is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.
In July 2005, we completed the acquisition of the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, LP’s entire Mid-Continent natural gas liquids fractionation business; Koch Pipeline Company, LP’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., now Chisholm Pipeline Holdings, L.L.C., which has a 50 percent ownership interest in Chisholm Pipeline Company; MBFF, LP, now ONEOK MBI, L.P., which owns an 80 percent interest in a 160,000 barrel per day fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, LLC, now ONEOK Vesco Holdings, L.L.C., an entity that owns a 10.2 percent interest in VESCO. These assets are included in our consolidated financial statements beginning on July 1, 2005.
In November 2004, we acquired Northern Plains, now known as ONEOK Partners GP, which then owned 82.5 percent of the general partner interest and approximately 500,000 limited partnership units, together representing a 2.73 percent ownership interest, in Northern Border Partners, L.P., now known as ONEOK Partners, from CCE Holdings, LLC for $175 million. Income derived from this investment was included in other income in our Other segment until January 1, 2006. See “Impact of New Accounting Standards” below for discussion of consolidation under EITF 04-5.
REGULATORY
Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment and our ONEOK Partners segment. See discussion of our Distribution segment’s regulatory initiative beginning on page 42.
IMPACT OF NEW ACCOUNTING STANDARDS
In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will not go into effect until our year ending December 31, 2008. Statement 158 requires us to recognize the overfunded or underfunded status of our plans as an asset or liability in the statement of financial position and to recognize changes in that funded status in other comprehensive income (loss) in the year in which the changes occur. See Note J of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for the impact of adoption of Statement 158.
Also in September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
In September 2006, the SEC staff issued SAB Topic 1N, “Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how to quantify the effect of an error on the financial statements. SAB 108 is effective for our year ended December 31, 2006. We have completed our review of the applicability of SAB 108 to our operations and have determined that it did not have an impact on our consolidated financial statements.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are evaluating our tax positions and anticipate FIN 48 will not have a significant impact on our results of operations.
In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 was effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that its impact was immaterial to our consolidated financial statements.
In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, which presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements, and we elected to use the prospective method. Accordingly, prior period financial statements have not been restated. The adoption of EITF 04-5 did not have an impact on our net income; however, reported revenues, costs and expenses reflect the operating results of ONEOK Partners. Additionally, we recorded a minority interest liability on our 2006 Consolidated Balance Sheet to recognize the 54.3 percent of ONEOK Partners that we do not own. We reflect our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive income (loss) at December 31, 2006, in our consolidated accumulated other comprehensive income (loss). The remaining 54.3 percent is reflected as an adjustment to minority interests in consolidated subsidiaries.
In December 2004, the FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as we have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation-Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R. As of December 31, 2006, there was $3.1 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.1 year. There was $10.1 million of unrecognized compensation cost related to our performance unit awards as of December 31, 2006, which is expected to be recognized over a weighted-average period of 1.4 years. The total unrecognized compensation cost related to nonvested stock options was not material.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty and that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.
The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.
We have discussed the development of and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.
Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 59 for amounts in our portfolio at December 31, 2006, that were determined by prices actively quoted, prices provided by other external sources and prices derived from other sources. The majority of our portfolio’s fair values are based on actual market prices. Transactions are also executed in markets for which market prices may exist but the market may be relatively inactive, thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values.
Market value changes result in a change in the fair value of our derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, options and swap transactions in order to hedge anticipated purchases and sales of natural gas and condensate, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flows. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.
Many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and therefore, upon election, are exempt from fair value accounting treatment.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
We assess our goodwill and intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. See Note E of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion. There were no impairment charges resulting from the July 1, 2006, impairment tests and no events indicating an impairment has occurred subsequent to that date. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. As shown below, we had $600.7 million of goodwill recorded on our Consolidated Balance Sheet as of December 31, 2006.
Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. Our ONEOK Partners segment had $450.7 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2006, that consisted of $295.2 million which is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life.
During 2006, we recorded a goodwill and asset impairment related to our ONEOK Partners segment’s Black Mesa Pipeline. For further discussion of this impairment, see page 39.
In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also the net sales proceeds from the anticipated sale of the plant. The sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations in accordance with Statement 144.
Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million and $33.4 million as of December 31, 2006 and 2005, respectively. Based on Statement 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly, we included this amount in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets.
We do not currently anticipate any additional goodwill or asset impairments to occur within the next year, but if such events were to occur over the long term, the impact could be significant to our financial condition and results of operations.
Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees who retire under our defined benefit pension plan with at least five years of service. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. Nonbargaining unit employees retiring between the ages of 50 and 55, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003, and gas union employees hired after July 1, 2004, who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note J of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Assumed health care cost trend rates have a significant effect on the amounts reported for our health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects.
During 2006, we recorded net periodic benefit costs of $21.6 million related to our defined benefit pension plans and $25.9 million related to postretirement benefits. We estimate that in 2007, we will record net periodic benefit costs of $29.1 million related to our defined benefit pension plan and $26.7 million related to postretirement benefits. In determining our estimated expenses for 2007, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 6.00 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our 2007 estimated net periodic benefit costs by approximately $1.7 million for our defined benefit pension plan and would not have a significant impact on our postretirement benefit plan. A decrease in our assumed discount rate to 5.75 percent would increase our 2007 estimated net periodic benefit costs by approximately $2.2 million for our defined benefit pension plan and $0.8 million for our postretirement benefit plan. For 2007, we anticipate our total contributions to our defined benefit pension plan and postretirement benefit plan to be $5.0 million and $13.4 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $15.4 million.
Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.
FINANCIAL AND OPERATING RESULTS
Consolidated Operations
The following table sets forth certain selected financial information for the periods indicated.
Operating Results - Net margin increased for 2006, compared with 2005, primarily due to:
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the consolidation of our investment in ONEOK Partners as required by EITF 04-5,
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the effect of the natural gas liquids assets acquired from Koch in our ONEOK Partners segment,
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strong commodity prices, higher gross processing spreads and increased natural gas transportation revenue in our ONEOK Partners segment, and
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improved natural gas basis differentials on transportation contracts, net of hedging activities, in our Energy Services segment.
For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 42.
Consolidated operating costs for 2006 increased, compared with 2005, primarily because of consolidation of the legacy ONEOK Partners operations and the natural gas liquids assets acquired in 2005, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.
Depreciation, depletion and amortization increased for 2006, compared with 2005, primarily due to the consolidation of the legacy ONEOK Partners operations, the Black Mesa Pipeline impairment, and the costs associated with the natural gas liquids assets acquired from Koch.
Operating income for 2006 includes the gain on sale of assets of $113.9 million related to ONEOK Partners’ sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006. For additional information, see discussion on page 30.
Equity earnings from investments increased $93.3 million in 2006, compared with 2005, primarily as a result of our adoption of EITF 04-5 as of January 1, 2006, which resulted in our consolidation of ONEOK Partners. ONEOK Partners holds various investments in unconsolidated affiliates, including a 50 percent interest in Northern Border Pipeline. Prior to January 1, 2006, ONEOK Partners was accounted for as an investment under the equity method.
Minority interests in income of consolidated subsidiaries, which reflects the remaining 54.3 percent of ONEOK Partners that we do not own, increased $222.0 million in 2006, compared with 2005, as a result of our 2006 adoption of EITF 04-5.
Net margin increased for 2005, compared with 2004, primarily due to:
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the effect of increased natural gas basis differentials and natural gas price volatility in our Energy Services segment,
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the impact of favorable commodity pricing for natural gas and NGL products on our ONEOK Partners segment,
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the effect of the natural gas liquids assets acquired from Koch in our ONEOK Partners segment, and
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the implementation of new rate schedules in Oklahoma for our Distribution segment.
Consolidated operating costs increased for 2005, compared with 2004, primarily because of costs related to the natural gas liquids assets acquired from Koch and increased employee benefit costs.
Depreciation, depletion and amortization increased for 2005, compared with 2004, primarily due to the costs associated with the natural gas liquids assets acquired from Koch. Further increases resulted from additional plant, property and equipment in our Distribution segment and regulatory asset amortization resulting from the Kansas Gas Service rate case.
Operating income for 2005 includes the gain on sale of assets in our ONEOK Partners segment of $264.2 million. This gain was the result of the sale of certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. in December 2005.
More information regarding our results of operations is provided in the discussion of each segment’s results. The discontinued component is discussed in our Discontinued Operations and Energy Services segment sections.
Key Performance Indicators - Key performance indicators reviewed by management include:
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earnings per share,
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return on invested capital, and
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shareholder appreciation.
For 2006, our basic and diluted earnings per share from continuing operations were $2.74 and $2.68, respectively, representing a 32 percent decrease in basic earnings per share and a 28 percent decrease in diluted earnings per share from continuing operations compared with 2005. For 2005, our basic and diluted earnings per share from continuing operations increased 81 percent and 75 percent, respectively, compared with 2004. Return on invested capital was 14.4 percent in 2006 compared with 23.0 percent in 2005 and 14.3 percent in 2004. The significantly higher earnings per share results in 2005 primarily related to the gain on the sale of our Texas gathering and processing assets which, in addition to the gain on the sale of our production assets, also increased our return on invested capital in 2005.
To evaluate shareholder appreciation, we compare ourselves with a group of 20 peer companies. For the year ended December 31, 2006, we ranked first in shareholder appreciation compared with our peers.
ONEOK Partners
Overview - Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5, and we elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are now included in our ONEOK Partners segment and all periods presented have been restated to reflect this change. We own 45.7 percent of
ONEOK Partners; the remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our 2006 Consolidated Statement of Income.
ONEOK Partners gathers and processes natural gas and fractionates NGLs primarily in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ operations include the gathering of natural gas production from crude oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed to remove water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream.
ONEOK Partners also gathers, stores, fractionates and treats mixed NGLs, and stores NGL purity products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. ONEOK Partners’ NGL assets connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key NGL market centers in Conway, Kansas, and Mont Belvieu, Texas.
Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, raw form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates each NGL component into marketable NGL purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively NGL purity products). These NGL purity products can then be stored or distributed to petrochemical, heating and motor gasoline manufacturers.
ONEOK Partners operates intrastate and FERC-regulated interstate natural gas transmission pipelines, natural gas storage and FERC-regulated and intrastate natural gas liquids gathering and distribution pipelines and nonprocessable natural gas gathering facilities. ONEOK Partners also provides interstate natural gas transportation service under Section 311(a) of the Natural Gas Policy Act.
Acquisition and Divestitures - The following acquisition and divestitures are described beginning on page 30.
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In April 2006, ONEOK Partners completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline in April 2007.
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In December 2005, we sold our natural gas gathering and processing assets located in Texas. This sale included approximately 3,700 miles of pipe and six processing plants with a capacity of 0.2 Bcf/d. The impact of these assets on our ONEOK Partners segment’s operating income for the year ended December 31, 2005, was a decrease of $42.0 million. Additionally, we sold approximately 10 miles of non-contiguous, natural gas gathering pipelines in Texas.
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In July 2005, we acquired natural gas liquids businesses from Koch. We also acquired Koch Vesco Holdings, LLC, an entity, which owns a 10.2 percent interest in VESCO. VESCO owns a gas processing complex near Venice, Louisiana. Additionally, we acquired the FERC-regulated assets that were part of the acquisition from Koch.
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our ONEOK Partners segment for the periods indicated.
Operating results - We began consolidating our investment in ONEOK Partners as of January 1, 2006, in accordance with EITF 04-5. We elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. See “Impact of New Accounting Standards” on page 31 for additional information.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are now included in our ONEOK Partners segment.
Net margin increased by $294.4 million for 2006, compared with 2005, primarily due to:
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an increase of $191.1 million from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,
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an increase of $101.8 million related to net margins on natural gas liquids gathering and distribution pipelines acquired from Koch in July 2005,
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an increase of $72.1 million from our legacy operations driven primarily by strong commodity prices, higher gross processing spreads and increased natural gas transportation revenues, and
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a decrease of $80.5 million resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
The increase in operating costs of $103.2 million for 2006, compared with 2005, is primarily related to the consolidation of the legacy ONEOK Partners operations as of January 1, 2006, and the natural gas liquids assets acquired in 2005, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.
Depreciation, depletion and amortization expense increased by $54.6 million for 2006, compared with 2005, primarily due to $37.9 million related to the consolidation of the legacy ONEOK Partners operations, $12.0 million for the Black Mesa Pipeline impairment and $15.5 million for the acquisition of natural gas liquids assets from Koch in 2005. These increases were offset by an $8.2 million decrease resulting from the December 2005 sale of natural gas gathering and processing assets located in Texas.
Operating income for 2006 includes the gain on sale of assets of $113.9 million related to ONEOK Partners’ sale of a 20 percent partnership interest in Northern Border Pipeline to TC Pipelines in April 2006. For more information, see discussion on page 30.
The increase in equity earnings from investments of $103.5 million for 2006 resulted primarily from ONEOK Partners’ 50 percent interest in Northern Border Pipeline and gathering and processing joint venture interests in the Powder River and Wind River Basins.
The $145.5 million increase in capital expenditures for 2006, compared with 2005, is primarily related to $80.4 million in expenditures by ONEOK Partners’ legacy operations and $36.7 million in expenditures related to Overland Pass Pipeline Company.
The $128.8 million increase in net margin for 2005, compared with 2004, is primarily due to:
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an increase of $83.8 million related to revenues on natural gas liquids assets acquired in July 2005,
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an increase of $20.5 million in natural gas transport revenues resulting from increased throughput due to favorable weather conditions for transportation, improved fuel position and significantly higher commodity prices,
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an increase of $18.8 million attributable to keep-whole contracts, net of hedging, due primarily to an increase in gross processing spread,
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an increase of $8.0 million due to higher natural gas and NGL prices on POP contracts, net of hedging, and
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an increase of $10.6 million related to increased storage revenues from renegotiated contracts, improved fuel position and higher commodity prices.
These increases were partially offset by:
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a decrease of $6.5 million due to the sale of certain natural gas gathering and processing assets located in Texas in December 2005 and
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a decrease of $5.8 million related to lower net margins on equity natural gas inventory sales.
The $43.2 million increase in operating costs for 2005, compared with 2004, is primarily due to:
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increased costs related to the acquired natural gas liquids assets of $33.7 million and
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higher employee costs and other operating costs offset in part by lower litigation costs as compared with 2004.
The increase in depreciation and amortization of approximately $17.2 million for 2005, compared with 2004, is primarily related to the newly acquired natural gas liquids pipelines.
Operating income for 2005 includes a $264.2 million gain on the sale of the natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. in December 2005. See Note B of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
The decrease in equity earnings from investments for 2005, compared with 2004, is primarily due to an impairment of $5.9 million recognized in 2005 related to a 50 percent equity investment in an Oklahoma gas plant that ONEOK Partners does not operate and a $2.6 million impairment charge related to one of its gas gathering partnerships.
The increase in capital expenditures for 2005, compared with 2004, is primarily related to well connects and additional compression expenditures.
Risk Management - ONEOK Partners uses commodity financial instruments, including NYMEX contracts, fixed price swaps and collars, which are primarily designated as cash flow hedges, to minimize earnings volatility related to natural gas, NGLs and condensate price fluctuations. The realized financial impact of the derivative transactions is included in our ONEOK Partners segment’s operating income in the period that the physical transaction occurs. The following table sets forth hedging information for 2007 for our ONEOK Partners segment.
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Black Mesa Pipeline - On December 31, 2005, our ONEOK Partners segment’s Black Mesa Pipeline’s transportation contract with the coal supplier of Mohave Generating Station (Mohave) expired and its coal slurry pipeline operations were shut down as expected. In June 2006, SCE completed a comprehensive study of the water source, coal supply and transportation issues and announced that it would no longer pursue the resumption of plant operations. In February 2007,
another Mohave co-owner, Salt River Project, announced it was ending its efforts to return the plant to service. Negotiations between various parties involved with Black Mesa Pipeline are ongoing.
During the second quarter of 2006, ONEOK Partners assessed its coal slurry pipeline operation in accordance with its accounting policies related to goodwill and asset impairment. Its evaluation of the Black Mesa Pipeline indicated a goodwill and asset impairment of $8.4 million and $3.6 million, respectively, which were recorded as depreciation and amortization in the second quarter of 2006. The reduction to our net income, net of minority interest and income taxes, was $3.0 million.
Distribution
Overview - Our Distribution segment provides natural gas distribution services to over two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers.
Selected Financial Information - The following table sets forth certain selected financial and operating information for our Distribution segment for the periods indicated.
Operating Results - Net margin increased $12.1 million for 2006, compared with 2005, due to:
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an increase of $42.3 million resulting from the implementation of new rate schedules, which was made up of $39.7 million in Oklahoma and $2.6 million in Texas,
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a decrease of $19.0 million primarily due to expiring riders and lower volumetric rider collections in Oklahoma,
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a decrease of $10.0 million in customer sales due to warmer weather in our entire service territory, and
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a decrease of $1.8 million due to reduced wholesale volumes in Kansas.
Operating costs increased $11.1 million for 2006, compared with 2005, due to:
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an increase of $17.2 million in labor and employee benefit costs,
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an increase of $1.7 million due to increased property taxes, and
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a decrease of $7.6 million in bad debt expense.
Depreciation, depletion and amortization decreased $2.6 million for 2006, compared with 2005, primarily due to:
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a decrease of $2.8 million in cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of 2005,
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a decrease of $2.9 million related to the replacement of our field customer service system in Texas during the first quarter of 2005, and
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an offsetting increase of $2.3 million for depreciation expense related to our investment in property, plant and equipment.
Net margin increased $30.4 million for 2005, compared with 2004, due to:
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an increase of $28.2 million resulting from the implementation of new rate schedules in Oklahoma,
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an increase of $2.3 million resulting from increased wholesale transactions in Kansas,
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an increase of $4.9 million due to the ad valorem tax recovery rider, which is offset in amortization expense, and
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an offsetting decrease of $5.2 million in customer sales volumes due to warmer weather.
Operating costs increased $18.7 million for 2005, compared with 2004, due to:
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an increase of $12.5 million in labor and employee benefit costs,
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an increase of $2.0 million in bad debt expense, and
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an increase of $3.2 million due to equipment leasing costs, higher vehicle fuel costs, and an insurance deductible related to Hurricane Rita.
Depreciation, depletion and amortization increased $8.0 million for 2005, compared with 2004, primarily due to:
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an increase of $2.9 million related to the replacement of our field customer service system in Texas,
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an increase of $3.5 million related to our investment in property, plant and equipment,
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an increase of $4.9 million due to amortization of the ad valorem tax recovery rider in Kansas, and
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an offsetting decrease of $3.2 million in pension expense amortization in Oklahoma which expired in 2004.
Selected Operating Data - The following tables set forth certain selected financial and operating information for our Distribution segment for the periods indicated.
Residential, commercial and industrial volumes decreased in 2006, compared with 2005, due to warmer weather, primarily in the first quarter of 2006, which affects residential and commercial customers.
Residential, commercial and industrial volumes decreased in 2005, compared with 2004, due to warmer weather, which primarily affects residential and commercial customers, as well as commercial customers migrating to new transportation rates as a result of lower minimum thresholds in Oklahoma.
Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes decreased for 2006, compared with 2005, due to reduced volumes available for sale.
Public authority natural gas volumes reflect volumes used by state agencies and school districts served by Texas Gas Service.
Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable and efficient operations. Our capital expenditure program included $54.9 million, $38.6 million and $35.0 million for new business development in 2006, 2005 and 2004, respectively. Increased new customer installation in the Austin and El Paso areas of Texas and the Tulsa and Oklahoma City areas of Oklahoma were primarily responsible for the increase in new business capital expenditures during 2006, compared with 2005.
Regulatory Initiatives
Oklahoma - On October 4, 2005, the OCC issued a final order on our application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. The Commission’s administrative law judge had recommended an increase in annual revenues of approximately $58.0 million in July 2005. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report.
Kansas - In May 2006, Kansas Gas Service announced that it filed a request with the KCC to increase its annual revenues by $73.3 million. Since its last rate case in 2003, Kansas Gas Service had invested approximately $170 million in its natural gas distribution system to provide service for 642,000 Kansas customers. This was the company’s first rate increase request in three years. The KCC had 240 days to issue a ruling on Kansas Gas Service’s application. In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other involved parties to increase annual revenues by approximately $52 million. The terms of the settlement were approved by the KCC in November 2006. The rate increase was effective for services rendered on or after January 1, 2007.
On June 24, 2005, the KCC issued an order authorizing the inclusion of the natural gas cost component of uncollectible customer accounts in rates for cost recovery. Kansas Gas Service began deferring the natural gas cost component of uncollectible accounts in July 2005 and began recovery in August 2006.
Texas - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $5.5 million in annual rate increases were approved and implemented in 2006.
Bargaining Unit - On October 25, 2006, a four-year labor contract was ratified between Kansas Gas Service and the International Brotherhood of Electrical Workers. The contract will expire on June 30, 2010.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.
Energy Services
Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease is 86 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current transportation capacity is 1.8 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products for value to our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Also, our storage and transportation capacity allows us opportunities to optimize these positions through our application of market knowledge and risk management skills.
Our Energy Services segment regularly conducts business with ONEOK Partners, our 45.7 percent owned affiliate, which comprises our ONEOK Partners segment. This segment also conducts business with our Distribution segment. These services are provided under agreements with market-based terms.
Due to seasonality of natural gas consumption, earnings are normally higher during the winter months than the summer months. Our Energy Services segment’s margins are subject to fluctuations during the year primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas. Natural gas sales volumes are typically higher in
the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices that occur during the winter heating months. During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet peak day demand obligations or market needs.
We manage our contracted transportation and storage capacity by utilizing derivative instruments such as over-the-counter forward, swap and option contracts and NYMEX futures and option contracts. We apply a combination of cash-flow and fair-value hedge accounting when implementing hedging strategies that take advantage of existing market conditions. See Note D of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. Additionally, certain hedging activity will not qualify for hedge or accrual accounting treatment; therefore, these non-trading transactions are economic hedges of our accrual transactions. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship.
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Energy Services segment for the periods indicated. In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. The transaction received FERC approval, and the sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations, in accordance with Statement 144. The discontinued operations are excluded from the financial and operating results below. For additional information, see discussion of discontinued operations on page 45.
Operating Results - Net margin increased $67.5 million for 2006, compared with 2005, primarily due to:
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an increase of $58.0 million in transportation margins, net of hedging activities, primarily due to improved natural gas basis differentials between Mid-Continent and Gulf Coast regions,
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an increase of $7.1 million in our natural gas trading operations primarily associated with favorable basis spread and fixed-price movement in our basis trading and fixed-price portfolios,
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a net increase of $0.9 million related to storage and marketing margins primarily due to:
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an increase of $7.1 million due to improved physical storage and marketing margins, net of hedging activities, and increased demand fees and optimization activities associated with peaking services, partially offset by,
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a decrease of $6.2 million related to power margins associated with a tolling transaction that expired December 31, 2005, and
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an increase of $1.5 million in retail activities due to improved physical margins.
Operating costs increased $3.7 million in 2006, compared with 2005, primarily due to increased employee-related costs.
Net margin increased $32.4 million for 2005, compared with 2004, primarily due to:
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an increase of $41.9 million in transportation margins, net of economic hedges, due to improved natural gas basis differentials primarily in the fourth quarter of 2005 associated with certain capacity held in the Mid-Continent region,
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an increase of $29.4 million in marketing margins due to:
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an increase of $22.6 million in wholesale physical marketing margins resulting from favorable natural gas price volatility primarily in the fourth quarter of 2005, and
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an increase of $6.8 million in power trading margins related to improved Electric Reliability Council of Texas (ERCOT) market heat-rates attributable to a 13.2 percent increase in cooling degree days compared to normal and a 10.0 percent increase in cooling days compared with the same period in 2004.
These increases in net margin were partially offset by:
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a net decrease of $18.3 million in storage margins from cash flow hedge ineffectiveness primarily related to natural gas basis movements attributable to anticipated storage withdrawals from the 2006/2007 heating season,
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a decrease of $18.4 million resulting from less favorable price movements in 2005 related to our natural gas fixed price activities, and
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a decrease of $2.2 million in retail activities related to reduced physical margins.
The $5.3 million increase in operating costs in 2005, compared with 2004, is primarily due to increased employee-related costs of $1.3 million and increased legal costs of $2.9 million.
Natural gas volumes marketed decreased for 2006, compared with 2005, primarily due to higher storage injections in the second and third quarters of 2006; warmer temperatures in the majority of our service territory in the first and fourth quarters of 2006; and decreased sales in our Canadian operations. Natural gas volumes increased in 2005, compared with 2004, due to our expanded Canadian operations, additional long-term transportation contracts and opportunities to sell into supply-constrained markets.
Our natural gas in storage at December 31, 2006, was 74.1 Bcf, compared with 62.1 Bcf at December 31, 2005. At both December 31, 2006 and 2005, our total natural gas storage capacity under lease was 86 Bcf.
The acquisition of natural gas storage capacity has become more competitive as a result of new entrants from the financial services sector, the increase in the spread between summer and winter natural gas prices, and natural gas price volatility. The increased demand for storage capacity has resulted in an increase in both the cost of leasing storage capacity and the required term of the lease. Longer terms for our storage capacity leases could result in significant increases in our contractual commitments.
At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter of 2004, we managed our Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.
Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3.” For derivative instruments considered held for trading purposes that result in physical delivery, the indicators in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.
For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. Prior periods have not been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
The following table shows the margins by activity, beginning with our reorganization on July 1, 2004.
Marketing and storage activities, net, primarily include physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used to manage our risk associated with these activities. The combination of owning supply, controlling strategic assets and risk management services allows us to provide commodity-diverse products and services to our customers such as peaking and load following services.
Retail marketing includes revenues from providing physical marketing and supply services coupled with risk management services to residential and small commercial and industrial customers.
Financial trading margin includes activities that are generally executed using financially settled derivatives. These activities are normally short-term in nature, with a focus of capturing short-term price volatility. Energy trading revenues, net, in our Consolidated Income Statements includes financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are required to be reported on a net basis.
DISCONTINUED OPERATIONS
Overview - In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors authorized management to pursue the sale in July 2005, which resulted in our former production segment being classified as held for sale beginning July 1, 2005. In accordance with Statement 144, we did not record any depreciation, depletion or amortization for our former production segment while it was classified as held for sale.
Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. We subsequently entered into an agreement to sell our Spring Creek power plant to Westar for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators.
These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our financial statements and related notes for all periods shown relating to our former production segment and our power generation business are reflected as discontinued operations. The sale of our former production segment and the sale of our power generation business are in line with our business strategy to sell assets when deemed to be less strategic or as other conditions warrant.
Selected Financial Information - The amounts of revenue, costs and income taxes reported in discontinued operations are shown in the table below for the periods indicated.
LIQUIDITY AND CAPITAL RESOURCES
General - Part of our strategy is to grow through strategic acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no material guarantees of debt or other similar commitments to unaffiliated parties. During 2006 and 2005, our capital expenditures were financed through operating cash flows and short- and long-term debt. Capital expenditures for 2006 were $376 million, compared with $250 million in 2005, exclusive of acquisitions.
Financing - Financing is provided through available cash, our commercial paper program and long-term debt. We also have credit agreements, as discussed below, which are used as a back-up for the commercial paper program and short-term liquidity needs. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and sale/leaseback of facilities. ONEOK Partners’ operations are also financed through operating cash flow, credit agreements and the issuance of debt and limited partner units.
The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. In addition to the short-term bridge financing agreement discussed below, the total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $750 million, and an additional $10 million is authorized for Guardian Pipeline. At December 31, 2006, we had no commercial paper outstanding, $58.5 million in letters of credit issued and available cash and temporary investments of approximately $78.3 million. At December 31, 2006, ONEOK Partners had $10 million in letters of credit issued, no borrowings outstanding under the five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement), and available cash of approximately $21.1 million. As of December 31, 2006, we could have issued $2.6 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of December 31, 2006, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, $1.5 billion of additional debt.
Currently, we have $48.2 million available under a shelf registration statement on Form S-3, for the issuance and sale of shares of our common stock, debt securities, preferred stock, stock purchase contracts and stock purchase units.
ONEOK Short-Term Bridge Financing Agreement - On July 1, 2005, we borrowed $1.0 billion under a new short-term bridge financing agreement to assist in financing our acquisition of assets from Koch. See Note B of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. During 2006, we repaid the facility in full, and it was terminated according to its terms.
ONEOK Five-Year Credit Agreement - In April 2006, we amended our 2004 $1.2 billion five-year credit agreement to accommodate the transaction with ONEOK Partners. This amendment included changes to the material adverse effect representation, the burdensome agreement representation and the covenant regarding maintenance of control of ONEOK Partners.
In July 2006, we amended and restated our 2004 $1.2 billion five-year credit agreement. The amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million. The interest rates applicable to extensions of credit under this agreement are based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings.
Under the five-year credit agreement we are required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
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a $500 million sublimit for the issuance of standby letters of credit,
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a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter,
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a requirement that we maintain the power to control the management and policies of ONEOK Partners, and
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a limit on new investments in master limited partnerships.
The debt covenant calculations in our five-year credit agreement exclude the debt of ONEOK Partners. At December 31, 2006, we had no borrowings outstanding under this agreement.
Our five-year credit agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of our businesses, transactions with affiliates, the use of proceeds and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends. At December 31, 2006, we were in compliance with these covenants.
ONEOK Uncommitted Line of Credit - We have a credit agreement with a commercial bank that gives us access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $15 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Federal Funds overnight rate, which is the rate that banks charge each other for the overnight borrowing of funds. This agreement remains in effect until canceled by the commercial bank or us. This agreement does not contain any covenants more restrictive than those in our $1.2 billion five-year credit agreement. This credit agreement is used to issue a $15.0 million standby letter of credit.
2006 Partnership Credit Agreement - In December 2006, ONEOK Partners amended its 2006 Partnership Credit Agreement. This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA (net income before interest expense, income taxes, and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland Pass Pipeline Company agreement from the covenant that limits ONEOK Partners’ ability to enter into agreements that restrict its ability to grant liens to the lenders under the 2006 Partnership Credit Agreement.
In March 2006, ONEOK Partners amended and restated its 2005 revolving credit agreement with certain financial institutions and increased the term for an additional five years, increased the facility to $750 million from $500 million, and lowered the pricing. The 2005 revolving credit agreement, as amended and restated, is referred to as the 2006 Partnership Credit Agreement.
Under the 2006 Partnership Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
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maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1, and
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maintaining a ratio of EBITDA to interest expense of greater than 3 to 1.
If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement may become immediately due and payable. At December 31, 2006, ONEOK Partners was in compliance with these covenants.
At December 31, 2006, a $10 million letter of credit was outstanding under the 2006 Partnership Credit Agreement. The letter of credit expires May 1, 2007.
ONEOK Partners Bridge Facility - In April 2006, ONEOK Partners entered into a $1.1 billion 364-day credit facility (Bridge Facility) with a syndicate of banks and borrowed $1.05 billion to finance a portion of its purchase of certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments. In September 2006, ONEOK Partners repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated according to its terms. See “ONEOK Partners Debt Issuance” below and Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further discussion regarding the issuance of senior notes.
ONEOK Partners Debt Issuance - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the 2012 Notes), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the 2016 Notes) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the 2036 Notes and collectively with the 2012 Notes and the 2016 Notes, the Notes). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006. The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.
ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts, commissions and expenses, but before offering expenses, were used to repay all of the amounts outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and sell and lease back its property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016, and October 1, 2036, respectively. ONEOK Partners will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Guardian Pipeline Senior Notes - ONEOK Partners’ acquisition of the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners resulted in the inclusion of $145.6 million of long-term debt in our 2006 Consolidated Balance Sheet. These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due quarterly through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.86 percent.
Guardian Pipeline’s senior notes contain financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. Beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1. At December 31, 2006, Guardian Pipeline was in compliance with its financial covenants.
Equity Units - On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock for each equity unit they owned. The number of shares that we issued for each stock purchase contract was determined based on our average closing price
over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.
Capitalization Structure - The following table sets forth our consolidated capitalization structure for the periods indicated.
We do not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in our five-year credit agreement, the debt of ONEOK Partners is excluded. At December 31, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 48 percent long-term debt and 52 percent equity, compared with 53 percent long-term debt and 47 percent equity at December 31, 2005.
Credit Ratings - Our credit ratings as of December 31, 2006, were as follows:
Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper borrowings would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to a $1.2 billion five-year credit agreement, which expires July 2011, and ONEOK Partners has access to a $750 million revolving credit agreement, which allows for an option to increase the commitments of the lenders up to an additional $250 million that expires March 2011.
ONEOK Partners’ $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer a repurchase of the senior notes at par value if the Moody’s and S&P debt ratings fall below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade ratings are not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016 and 2036 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016 and 2036 to declare those notes immediately due and payable in full. ONEOK Partners may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.
Our Energy Services segment relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit requirements with most of our counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. A decline in our credit rating below investment grade may also significantly impact other business segments. At December 31, 2006, we could have been required to fund approximately $54.5 million for counterparties with which we have a Credit Support Annex according to our International Swaps and Derivatives Association Agreements.
Other than the note repurchase obligations and the margin requirement for our Energy Services segment described above, we have determined that we do not have significant exposure to the rating triggers under our commercial paper agreement, trust indentures, building leases, equipment leases, marketing, trading and risk contracts, and other various contracts. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. ONEOK’s credit agreements contain provisions that would cause the cost to borrow funds to increase if our credit rating is negatively adjusted. ONEOK Partners’ credit agreements have similar provisions. An adverse rating change is not defined as a default of our credit agreements.
ONEOK Partners’ Class B Units - The limited partner units we received from ONEOK Partners were newly created Class B units which are presently subordinated to the common units with respect to the payment of the minimum quarterly distribution, which is $0.55 per unit, and thereafter, have the same right to receive minimum quarterly distributions as those received by the holders of the common units. If distributions to all unitholders exceed $0.55 per unit, the holders of common units and holders of the Class B units receive the same distribution per unit. The Class B units have limited voting rights. Distributions on the Class B units were prorated from the date of issuance. ONEOK Partners is required to hold a special election for holders of common units as soon as practical, but no later than April 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to ONEOK Partners’ partnership agreement.
ONEOK Partners will hold a special election for holders of common units on March 29, 2007, subject to adjournment, to approve the conversion of the Class B units into common units and to approve certain amendments to its partnership agreement. The proposed amendments to its partnership agreement would grant voting rights for common units held by its general partner if a vote is held to remove its general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the conversion and the amendments are approved by the common unitholders, the Class B units will automatically be eligible to convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the amount payable on such Class B units would increase to 110 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove us or our affiliates as the general partner of ONEOK Partners at any time prior to the approval of the conversion and amendment described above, the amount payable on such Class B units would increase to 123.5 percent of the distributions payable with respect to the common units, and 125 percent of the distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated to the common units with respect to the minimum quarterly distributions unless and until the conversion described above has been approved.
Capital Projects - In June 2006, ONEOK Partners signed a non-binding letter of intent to form a joint venture with Boardwalk Pipeline Partners, LP and Energy Transfer Partners, LP to construct a new interstate pipeline originating in north Texas, crossing Oklahoma and Arkansas and terminating in Coahoma, Mississippi at a new interconnect with Texas Gas Transmission, L.L.C. The proposed interstate pipeline would have created new pipeline capacity for constrained wellhead production in north Texas and central Oklahoma and would have initial capacity of up to 1.0 Bcf/d. In August 2006, Energy Transfer Partners, LP withdrew from the joint venture. In 2007, ONEOK Partners withdrew from the letter of intent, but continues to work with Boardwalk Pipeline Partners, LP and others to determine the feasibility of a project to deliver incremental natural gas volumes to Texas Gas Transmission L.L.C. Any transaction is still subject to negotiation and execution of definitive agreements.
In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company, for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction and will operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $216 million excluding AFUDC to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a
combination of short- or long-term debt or equity. The project requires the approval of various state and federal regulatory authorities.
In October 2006, Guardian Pipeline, a subsidiary of ONEOK Partners, filed its application for a certificate of public convenience and necessity with the FERC for authorization to construct and operate approximately 110 miles of new mainline pipe, two compressor stations, seven meter stations and other associated facilities. The pipeline expansion will extend Guardian Pipeline from the Milwaukee, Wisconsin area to the Green Bay, Wisconsin area. The project is supported by long-term shipper commitments. The cost of the project is estimated to be $241 million excluding AFUDC, with a targeted in-service date of November 2008.
In March 2006, Midwestern Gas Transmission, a subsidiary of ONEOK Partners, accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. An organization which is opposed to, and includes landowners affected by, the project filed a request for rehearing and for a stay of the March 2006 Order. In August 2006, the FERC denied those requests. The Eastern Extension Project will add 31 miles of pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity with total capital expenditures estimated to be $35 million, excluding AFUDC. The proposed in-service date is the fourth quarter of 2007. Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee, and several interstate pipelines near Joliet, Illinois.
In January 2007, ONEOK Partner’s subsidiary Crestone Powder River announced that Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines resulting in 649 MMcf/d of additional capacity in the Powder River basin. The expansion will cost approximately $110 million and will occur in two phases with 240 MMcf/d in service by October 2007 and 409 MMcf/d by January 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. Crestone Powder River owns approximately 37 percent of Fort Union Gas Gathering.
Stock Repurchase Plan - A total of 15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005, to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. During 2005, we repurchased 7.5 million shares of our common stock pursuant to this plan. On August 7, 2006, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million, which completed the plan approved by our Board of Directors. Under the terms of the accelerated repurchase agreement, we repurchased 7.5 million shares immediately from UBS. UBS then borrowed 7.5 million of our shares and will purchase shares in the open market to settle its short position. Our repurchase is subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment can be settled, at our option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to ONEOK common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” In February 2007, the forward purchase contract settled for a cash payment of $20.1 million, which was recorded in equity. We have no remaining shares authorized for repurchase under our stock repurchase plan.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that ONEOK’s and ONEOK Partners’ current commercial paper program and lines of credit are adequate to meet our liquidity requirements associated with commodity price volatility.
Pension and Postretirement Benefit Plans - We calculate benefit obligations based upon generally accepted actuarial methodologies using the projected benefit obligation (PBO) for pension plans and the accumulated postretirement benefit obligation for other postretirement plans. Pension costs and other postretirement obligations as of December 31 are determined using a September 30 measurement date. The benefit obligations are the actuarial present value of all benefits attributed to employee service rendered. The PBO is measured using the pension benefit formula and assumptions as to future compensation levels. A plan’s funded status is calculated as the difference between the benefit obligation and the fair value of plan assets. Our funding policy for the pension plans is to make annual contributions in accordance with regulations under the Internal Revenue Code and in accordance with generally accepted actuarial principles. Contributions made to our pension plan and postretirement benefit plan in 2006 were $1.8 million and $2.5 million, respectively. Additionally, we made benefit payments for our postretirement benefit plan of $11.4 million in 2006. For 2007, we anticipate our total
contributions to our pension plan and postretirement benefit plan to be $5.0 million and $13.4 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $15.4 million. We believe we have adequate resources to fund our obligations under our plans.
ENVIRONMENTAL LIABILITIES
We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure our investors that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have commenced remediation on 11 sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, have commenced soil remediation at an additional site, and we expect to commence soil remediation on the other two sites in 2007. We have begun site assessment at the remaining site where no active remediation has occurred.
To date, we have incurred remediation costs of $6.0 million and have accrued an additional $6.0 million related to the sites where we have commenced or will soon commence remediation. The $6.0 million estimate of future remediation costs for these sites is based on our environmental assessments and remediation plans approved to date by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing expense estimates do not consider potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.
CASH FLOW ANALYSIS
Our Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each category. Discontinued operations accounted for approximately $77.2 million and $16.9 million in operating cash inflows for the years ended December 31, 2005 and 2004, respectively. Discontinued operations accounted for approximately $44.4 million and $52.9 million in investing cash outflows for the years ended December 31, 2005 and 2004, respectively, and did not account for any financing cash flows. The absence of cash flows from our discontinued operations is not expected to have a significant impact on our future cash flows.
Operating Cash Flows - Operating cash flows increased by $1.04 billion for 2006, compared with 2005, primarily as a result of changes in components of working capital which increased operating cash flows by $56.9 million compared with a decrease of $585.7 million for the same period last year as a result of decreased accounts receivable, decreased inventories and decreased accounts payable. The impact of lower commodity prices on accounts receivable, accounts payable and natural gas inventory positively impacted operating cash flows in 2006 compared with 2005.
The increase in 2006 operating cash flows was also impacted by the consolidation of ONEOK Partners as of January 1, 2006, due to EITF 04-5. During the year ended December 31, 2006, we received $123.4 million in distributions, primarily from Northern Border Pipeline, compared with distributions primarily from ONEOK Partners of $11.0 million in the prior year.
Operating cash flows decreased by $404.5 million for the year ended December 31, 2005, compared with the same period in 2004. The decrease in operating cash flows was primarily the result of changes in components of working capital. This decrease primarily related to increased accounts receivable and natural gas inventory, partially offset by increased accounts payable. The impact of higher commodity prices on accounts receivable, accounts payable and natural gas inventory negatively impacted operating cash flows for 2005 compared with 2004.
There is typically a lag between when payment is made for natural gas purchased for our distribution customers and when the customers are billed. This is due to the cycle billing process where distribution customers are billed throughout the month. Under level prices, this lag would have no impact on cash flows from year to year, but with lower prices as experienced in 2006, this lag resulted in a positive impact on cash flows. Conversely, with increased prices as experienced in 2005, this lag resulted in a negative impact on cash flows.
Our Energy Services segment’s deposits, or margin requirements, increase or decrease from year to year based on the level of open positions on our contracts, as well as commodity prices and price volatility. With the increase in commodity prices at December 31, 2005, we were required to meet additional margin requirements, which also negatively impacted operating cash flows for 2005. Margin requirements declined in 2006 resulting in increased cash flow.
Investing Cash Flows - Our ONEOK Partners segment received $297.0 million for the sale of a 20 percent partnership interest in Northern Border Pipeline in April 2006. Our Energy Services segment received $53.0 million for the sale of our discontinued component, Spring Creek.
Acquisitions in 2006 primarily relate to our ONEOK Partners segment acquiring the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million. This purchase increased ONEOK Partners’ ownership interest to 100 percent. We also purchased from TransCanada its 17.5 percent general partner interest in ONEOK Partners for $40 million. This purchase resulted in our ownership of the entire 2 percent general partner interest in ONEOK Partners. Additionally, ONEOK Partners paid $11.6 million to Williams for a 99 percent interest in, and initial capital expenditures related to, the Overland Pass Pipeline Company.
Acquisitions in 2005 primarily represent the purchase of the Koch assets. The sale of our former production segment resulted in proceeds from the sale of a discontinued component. The proceeds from the sale of assets in 2005 primarily resulted from the sale of our natural gas gathering and processing assets located in Texas. Additionally, the sale of Cimarex Energy Company common stock, formerly Magnum Hunter Resources (MHR) common stock, is also included in proceeds from sale of assets. This common stock was acquired upon exercise of MHR stock purchase warrants in February 2005, resulting in our paying $22.7 million, which is included in changes in other investments, net.
Acquisitions in 2004 represent the cash purchase of Northern Plains, now known as ONEOK Partners GP. Increased capital expenditures in 2004 were primarily incurred by our discontinued former production segment. Proceeds from the sale of assets include the sales of certain natural gas transmission and gathering pipelines, compression assets, natural gas distribution systems and investments in 2004.
Financing Cash Flows - During 2006, we paid $165.3 million in distributions to minority interests, which primarily resulted from our consolidation of ONEOK Partners in accordance with EITF 04-5 as of January 1, 2006, and represents distributions to the unitholders of the 54.3 percent of ONEOK Partners that we do not own.
We also paid $281.4 million to repurchase 7.5 million shares of our common stock in August 2006 pursuant to the plan approved by our Board of Directors.
In 2006, we repaid the remaining $900 million outstanding on our $1.0 billion short-term bridge financing agreement. During the second quarter of 2006, ONEOK Partners borrowed $1.05 billion under the ONEOK Partners Bridge Facility to
finance a portion of the acquisition of the ONEOK Energy Assets and $77 million under the 2006 Partnership Credit Agreement to acquire the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners. During the third quarter of 2006, ONEOK Partners completed the underwritten public offering of senior notes totaling $1.39 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding of the $1.05 billion borrowed under ONEOK Partners Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement.
In March 2006, ONEOK Partners borrowed $33 million under the 2006 Partnership Credit Agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a premium of $3.6 million.
On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement. See the “Liquidity and Capital Resources” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation on page 48 for additional discussion regarding the equity unit conversion.
During 2005, we borrowed $1.0 billion under our short-term bridge financing agreement to assist in financing the acquisition of natural gas liquids assets from Koch. We funded the remaining acquisition cost through our commercial paper program. We reduced our indebtedness under our short-term bridge financing agreement by $100.0 million as a result of a required prepayment due to the sale of our former production segment.
During 2005, we paid $233.0 million to repurchase 7.5 million shares of our stock pursuant to the plan approved by our Board of Directors.
In December 2005, we made an early redemption of our 7.75 percent $300.0 million long-term notes with a stated maturity of August 2006. In addition to the principal payment, we were required to pay a make-whole call premium of $5.7 million and accrued interest of $8.7 million for a total payment of $314.4 million. We funded this early redemption with the proceeds from the sale of our natural gas gathering and processing assets located in Texas.
In June 2005, we issued $800 million of long-term notes and used a portion of the proceeds to repay commercial paper. The commercial paper had been issued to finance the Northern Border Partners acquisition, to repay $335 million of long-term debt that matured on March 1, 2005, and to meet operating needs. This increase was partially offset by $643 million in payments on notes payable and commercial paper, which represents the cash received from the sale of our former production segment, and payments made in the normal course of operations.
During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swaps. The $20.2 million payment has been recorded as a reduction in long-term debt and will be recognized in the income statement over the term of the debt instruments originally hedged. In the second quarter of 2005, we terminated $500 million of our treasury rate-lock agreements, which resulted in our paying $2.4 million. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.
During the first quarter of 2004, we repaid $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the second half of 2004, we issued $644 million of notes payable, which includes the acquisition of Northern Plains, now known as ONEOK Partners GP, and funds used in the ordinary course of business.
Also in the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock-in savings and generate a positive cash flow of $91.8 million, which included $8.9 million of interest savings previously recognized. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. The proceeds received upon termination of the interest rate swaps, net of amounts previously recognized, will be recognized in the income statement over the term of the debt instruments originally hedged.
During the first quarter of 2004, we sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2006, and reflects the consolidation of ONEOK Partners based on EITF 04-5. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Long-term Debt - Long-term debt as reported in our Consolidated Balance Sheets includes unamortized debt discount and the mark-to-market effect of interest rate swaps.
Interest Payments on Debt - Interest expense is calculated by taking long-term debt and multiplying it by the respective coupon rates, adjusted for active swaps.
Operating Leases - We lease various buildings, facilities and equipment, which are accounted for as operating leases. We lease vehicles which are accounted for as operating leases for financial purposes and capital leases for tax purposes.
Pension and Other Postretirement Benefit Plans - No payment amounts are provided for our pension and other postretirement benefit plans in the “Thereafter” column since there is no termination date for these plans.
Purchase Commitments - Purchase commitments exclude commodity purchase contracts.
Firm Transportation Contracts - Our Distribution segment is a party to fixed price transportation contracts. However, the costs associated with these contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Some of the statements contained and incorporated in this Annual Report on Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report on Form 10-K
identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should” or similar phrases.
You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
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actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;
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the effects of weather and other natural phenomena on our operations, including energy sales and prices and demand for pipeline capacity;
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competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;
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the capital intensive nature of our businesses;
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the profitability of assets or businesses acquired by us;
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risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
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economic climate and growth in the geographic areas in which we do business;
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the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;
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the uncertainty of estimates, including accruals and costs of environmental remediation;
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the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil;
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the effects of changes in governmental policies and regulatory actions, including changes with respect to income taxes, environmental compliance, and authorized rates or recovery of gas and gas transportation costs;
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the impact of recently issued and future accounting pronouncements and other changes in accounting policies;
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the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;
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the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
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the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock and bond market returns;
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risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
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the results of administrative proceedings and litigation, regulatory actions and receipt of expected regulatory clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;
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our ability to access capital at competitive rates or on terms acceptable to us;
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risks associated with adequate supply to our gas gathering and processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
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the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
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the impact of the outcome of pending and future litigation;
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the possible loss of gas distribution franchises or other adverse effects caused by the actions of municipalities;
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the impact of unsold pipeline capacity being greater or less than expected;
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the ability to market pipeline capacity on favorable terms, including the affects of:
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future demand for and prices of natural gas;
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competitive conditions in the overall natural gas and electricity markets;
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availability of supplies of Canadian and United States natural gas;
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availability of additional storage capacity;
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weather conditions; and
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competitive developments by Canadian and U.S. natural gas transmission peers;
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our ability to successfully transfer ONEOK Partners’ operations from Omaha to Tulsa;
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performance of contractual obligations by our customers and shippers;
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the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
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timely receipt of approval by applicable governmental entities for construction and operation of our pipeline projects and required regulatory clearances;
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our ability to acquire all necessary rights-of-way permits and consents in a timely manner, and our ability to promptly obtain all necessary materials and supplies required for construction, and our ability to construct pipelines without labor or contractor problems;
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our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing and transportation facilities;
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the composition and quality of the natural gas we gather and process in our plants and transport on our pipelines;
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the efficiency of our plants in processing natural gas and extracting NGLs;
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the mechanical integrity of facilities operated;
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demand for our services in the proximity of our facilities;
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the impact of potential impairment charges;
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our ability to control operating costs;
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the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
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acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities or our suppliers’ or shippers’ facilities; and
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the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. Our risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price and credit risk management, and marketing and trading activities. The committee also monitors risk metrics including value-at-risk (VAR) and mark-to-market losses. We have a corporate risk control organization led by our vice president of audit, business development and risk control, who is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.
COMMODITY PRICE RISK
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
We are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs, and crude oil prices. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchase and sale agreements, existing physical natural gas in storage, and basis risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor our market risk exposure.
ONEOK Partners
ONEOK Partners is exposed to commodity price risk as its interstate and intrastate pipelines collect natural gas from its customers for operations or as part of their fee for services provided. When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines must buy or sell natural gas, or use natural gas from inventory, and are exposed to commodity price risk. At December 31, 2006, there were no hedges in place with respect to natural gas price risk from its interstate and intrastate pipeline operations.
Also, ONEOK Partners is exposed to commodity price risk primarily as a result of NGLs in storage, spread risk associated with the relative values of the various components of the NGL stream and the relative value of NGL purchases at one location and sales at another location, known as basis risk. ONEOK Partners has not entered into any hedges with respect to its NGL marketing activities.
Lastly, ONEOK Partners is exposed to commodity price risk primarily as a result of revenue realized from the sale of commodities received in exchange for its gathering and processing services. ONEOK Partners’ primary exposure arises from the relative price differential between natural gas and NGLs with respect to its keep-whole processing contracts and the sale of natural gas, NGLs and condensate with respect to its POP contracts. To a lesser extent, ONEOK Partners is exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. ONEOK Partners uses commodity derivative contracts and fixed-price physical contracts, including NYMEX-based futures, collars and over-the-counter swaps, which are all designated as cash flow hedges, to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations. The following table sets forth ONEOK Partners’ hedging information for 2007.
ONEOK Partners’ commodity price market risk is estimated as a hypothetical change in the price of natural gas, NGLs and crude oil at December 31, 2006. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates that a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.4 million, excluding the effects of hedging. ONEOK Partners estimates that a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $2.1 million, excluding the effects of hedging. ONEOK Partners estimates that a $0.10 per MMBtu increase in the price of natural gas would decrease annual net margin by approximately $0.1 million, excluding the effects of hedging. The above estimates of commodity price risk do not include any effects on demand for its services that might be caused by, or arise in conjunction with, price changes. For example, increased commodity prices may reduce demand for ONEOK Partners’ storage and transportation services or may be caused by factors, such as weather, that increase demand for such services.
Distribution
Kansas Gas Service and certain jurisdictions of Texas Gas Service use derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect their customers from upward volatility in the market price of natural gas. At December 31, 2006, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 2.0 Bcf, which represents part of their gas purchase requirements for the 2006/2007 winter heating months. Gains or losses associated with the Kansas Gas Service hedges are included in and recoverable through the monthly PGA. At December 31, 2006, Texas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 0.6 Bcf, which represents part of their gas purchase requirements for the 2006/2007 winter heating months.
Energy Services
Our Energy Services segment is exposed to commodity price risk, including basis risk, arising from natural gas in storage and index-based purchases and sales of natural gas at various market locations. We minimize the volatility of our exposure to commodity price risk through the use of derivative instruments, which, under certain circumstances, are designated as cash flow or fair value hedges. We are also exposed to commodity price risk from fixed price purchases and sales of natural gas,
which we hedge with derivative instruments. Both the fixed price purchases and sales and related derivatives are recorded at fair value.
Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding derivative instruments that have been declared as either fair value or cash flow hedges.
The net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities. Fair value estimates consider the market in which the transactions are executed. The market in which exchange traded and over-the-counter transactions are executed is a factor in determining fair value. We utilize third-party references for pricing points from NYMEX and third-party over-the-counter brokers to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective of current market prices. Fair values are subject to change based on valuation factors. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.
Maturity of Energy Trading Contracts - The following table provides a detail of our Energy Services segment’s maturity of derivatives based on injection and withdrawal periods from April through March. This maturity schedule is consistent with our business strategy. Executory storage and transportation contracts and their related hedges are not included in the following table.
(a) Fair value is the mark-to-market component of forwards, futures, swaps and options, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from energy marketing and risk management activities in our Consolidated Balance Sheets.
(b) Values are derived from the energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts.
(c) Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Energy price information by location is readily available because of the large energy broker network.
(d) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.
For further discussion of trading activities and assumptions used in our trading activities, see the “Critical Accounting Policies and Estimates” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Annual Report on Form 10-K. Also, see Note D of Notes to Consolidated Financial Statements in this Form 10-K.
Value-at-Risk (VAR) Disclosure of Market Risk - We measure market risk in the energy marketing and risk management, trading and non-trading portfolios of our Energy Services segment using a VAR methodology, which estimates the expected maximum loss of the portfolio over a specified time horizon within a given confidence interval. Our VAR calculations are based on the Monte Carlo approach. The quantification of market risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance, to determine risk targets and set position limits. The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation. Inputs to the calculation include prices, volatilities, positions, instrument valuations and the variance-covariance matrix. Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements. We rely on VAR to determine the potential reduction in the portfolio values arising from changes in market conditions over a defined period. While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR. Different assumptions and approximations could produce materially different VAR estimates.
Our VAR exposure represents an estimate of potential losses that would be recognized for our non-regulated businesses’ energy marketing and risk management, non-trading and trading portfolios of derivative financial instruments, physical contracts and natural gas in storage due to adverse market movements. A one-day time horizon and a 95 percent confidence level were used in our VAR data. Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and natural gas in storage. VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.
The potential impact on our future earnings, as measured by the VAR, was $14.9 million and $29.5 million at December 31, 2006 and 2005, respectively. The following table details the average, high and low VAR calculations for the periods indicated.
Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in the portfolios during the year. The increase in VAR for 2006, compared with 2005, was due to higher average commodity prices beginning in the latter part of the third quarter 2005 and was prevalent into the second quarter 2006. In particular, there was significant price volatility in the latter part of the third quarter of 2005 due to weather-related events.
To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position.
INTEREST RATE RISK
General - We are subject to the risk of interest rate fluctuation in the normal course of business. We manage interest rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest rate swaps. Fixed-rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2006, the interest rate on 82.9 percent of our long-term debt, exclusive of the debt of our ONEOK Partners segment, was fixed after considering the impact of interest rate swaps, while the interest rate on 92.6 percent of ONEOK Partners’ long-term debt was fixed after considering the impact of interest rate swaps.
At December 31, 2006, a 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by $5.0 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
Fair Value Hedges - In prior years, we and ONEOK Partners terminated various interest rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2006 for all terminated swaps was $10.1 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
Currently, $490 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through December 31, 2006, the weighted average interest rate on the $490 million of debt increased from 6.64 percent to 7.18 percent. At December 31, 2006, we recorded a net liability of $13.5 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $13.5 million to recognize the change in the fair value of the related hedged liability. See Note I of Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.
Total savings for both terminated and active swaps for 2006 were $7.6 million, compared with the savings of $10.7 million in 2005. Total swap savings for 2007 is expected to be $8.1 million.
Prior to the issuance of the $800 million of notes in the second quarter of 2005, we entered into $500 million in treasury rate-lock agreements to hedge the changes in cash flows of our anticipated interest payments from changes in treasury rates prior to the issuance of the notes. Upon the issuance of the notes in June 2005, we paid $2.4 million related to the termination of the treasury rate-lock agreements. This amount, net of tax, has been recorded to accumulated other comprehensive income (loss) and will be recognized in the income statement over the term of the related debt issuances.
CURRENCY RATE RISK
With our Energy Services segment’s expansion into Canada, we are subject to currency exposure related to our firm transportation and storage contracts. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net margin. At December 31, 2006 and 2005, our exposure to risk from currency translation was not material and there was no material currency translation gain or loss recorded.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
ONEOK, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (Item 9A), that ONEOK, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). ONEOK, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that ONEOK, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on COSO. Also, in our opinion, ONEOK, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 28, 2007, which expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Tulsa, Oklahoma
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
ONEOK, Inc.:
We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ONEOK, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note A of Notes to the Consolidated Financial Statements, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans,” Emerging Issues Task Force Issue 04-5, “Determining Whether a General Partner, or General Partners as a Group Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” and SFAS No. 123R, “Share-Based Payment.”
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of ONEOK, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Tulsa, Oklahoma
February 28, 2007
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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
See accompanying Notes to Consolidated Financial Statements.
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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Continued)
ONEOK, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF ACCOUNTING POLICIES
Nature of Operations - We purchase, transport, store and distribute natural gas. We are the largest natural gas distributor in Oklahoma and Kansas and the third largest natural gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers. Our largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services operation is engaged in wholesale and retail natural gas marketing and trading activities and provides services to customers in many states and Canada. We are the sole general partner and own 45.7 percent of ONEOK Partners, L.P. (NYSE: OKS), a publicly traded limited partnership. ONEOK Partners gathers, processes, stores and transports natural gas in the United States and owns a natural gas liquids system that connects much of the NGL supply in the Mid-Continent region with key market centers.
Critical Accounting Policies
The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.
Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. The majority of our portfolio’s fair values are based on actual market prices. Transactions are also executed in markets for which market prices may exist but the market may be relatively inactive, thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values.
Market value changes result in a change in the fair value of our derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period.
To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, options and swap transactions in order to hedge anticipated purchases and sales of natural gas and condensate, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flows. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings during the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.
Many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and therefore, upon election, are exempt from fair value accounting treatment.
See Note D for more discussion of derivatives and risk management activities.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
We assess our goodwill and intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. See Note E for more discussion of goodwill.
Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. Our ONEOK Partners segment had $450.7 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2006 of which $295.2 million is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life.
During 2006, we recorded a goodwill and asset impairment related to ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which were recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million.
In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also the net sales proceeds from the anticipated sale of the plant. The sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations in accordance with Statement 144.
Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million and $33.4 million as of December 31, 2006 and 2005, respectively. Based on Statement 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly, we included this amount in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets.
We do not currently anticipate any additional goodwill or asset impairments to occur within the next year, but if such events were to occur over the long term, the impact could be significant to our financial condition and results of operations.
Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees who retire under the retirement plan with at least five years of service. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. Nonbargaining unit employees retiring between the ages of 50 and 55, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003, and gas union employees hired after July 1, 2004, who elect postretirement medical coverage pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note J for more discussion of pension and postretirement employee benefits.
In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” which was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31, which will not go into effect until our year ending December 31, 2008. Statement 158 requires us to recognize the overfunded or underfunded status of our plans as an asset or liability in the statement of financial position and to recognize changes in that funded status in other comprehensive income (loss) in the year in which the changes occur. See Note J for the impact of adoption of Statement 158.
Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, either positive or negative, on earnings. See Note K for more discussion of contingencies.
Significant Accounting Policies
Consolidation - The consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee; conversely, if we do not have the ability to exercise significant influence, then we use the cost method. Impairment of equity and cost method investments is assessed when the impairments are other than temporary.
In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” which presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements, and we elected to use the prospective method. Accordingly, prior period financial statements have not been restated. The adoption of EITF 04-5 did not have an impact on our net income; however, reported revenues, costs and expenses reflect the operating results of ONEOK Partners. Additionally, we recorded a minority interests liability on our 2006 Consolidated Balance Sheet to recognize the 54.3 percent of ONEOK Partners that we do not own. We reflected our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive income (loss) at December 31, 2006, in our consolidated accumulated other comprehensive income (loss). The remaining 54.3 percent is reflected as an adjustment to minority interests in consolidated subsidiaries.
Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
Inventories - Materials and supplies are valued at average cost. Noncurrent natural gas in storage is classified as property and is valued at cost. Cost of current natural gas in storage for Oklahoma Natural Gas is determined under the last-in, first-out (LIFO) methodology. The estimated replacement cost of current natural gas in storage was $45.4 million and $70.2 million at December 31, 2006 and 2005, respectively, compared with its value under the LIFO method of $60.7 million and $56.2 million at December 31, 2006 and 2005, respectively. Current natural gas and NGLs in storage for all other companies are determined using the weighted average cost method.
In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 was effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that its impact was immaterial to our consolidated financial statements.
Property - The following table sets forth our property, by segment, for the periods presented.
Regulated Property - Regulated properties are stated at cost, which includes AFUDC. The AFUDC represents the capitalization of the estimated average cost of borrowed funds used during the construction of major projects and is recorded as a credit to interest expense. Depreciation is calculated using the straight-line method based on rates prescribed for ratemaking purposes.
Certain 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 an entire operating unit or system are recognized in income.
We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.
The average depreciation rates for our regulated property are set forth in the following table for the periods indicated.
Other Property - Gas processing plants, natural gas liquids fractionation plants and all other properties are stated at cost. Gas processing plants, natural gas liquids fractionation plants and all other property and equipment are depreciated using the straight-line method over the estimated useful life.
Environmental Expenditures - We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information becomes available or circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Revenue Recognition - Our ONEOK Partners segment includes gathering and processing, natural gas liquids, pipelines and storage, and interstate natural gas pipeline operations. ONEOK Partners’ gathering and processing operations record revenue when gas is processed in or transported through company facilities. ONEOK Partners’ natural gas liquids operations record operating revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the month services are provided. Operating revenue for ONEOK Partners’ pipelines and storage and interstate natural gas pipelines operations is recognized based upon contracted capacity and actual volumes transported and stored under service agreements in the period services are provided.
Our Distribution segment recognizes revenue when services are rendered or product is delivered. Major industrial and commercial natural gas distribution customers are invoiced as of the end of each month. Certain natural gas distribution customers, primarily residential and some commercial are invoiced on a cyclical basis throughout the month, and we accrue
unbilled revenues at the end of each month. Tariff rates for residential and commercial Oklahoma Natural Gas, Kansas Gas Service and some Texas Gas Service customers contain a temperature normalization clause that provides for billing adjustments from actual volumes to normalized volumes during the winter heating season. A flat monthly service fee is included in the authorized rate design for Texas Gas Service in El Paso to protect customers from abnormal rate fluctuations due to weather.
Our Energy Services segment also recognizes revenue when services are rendered or product is delivered. Wholesale and retail customers are invoiced as of the end of each month based on physical sales. Our fixed-price physical sales are accounted for as derivatives and are marked at fair value. We subsequently hedge the exposure of the fixed-price transactions and recognize the earnings in the month the transaction realizes. Demand payments for contracted storage capacity are recognized when the service is provided; however, the revenue associated with the commodity in storage is recognized upon delivery, and typical storage withdrawals are higher during the winter heating months.
Accounts receivable from customers are reviewed regularly for collectibility. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured.
Income Taxes - Deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas. For all other operations, the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are evaluating our tax positions and anticipate FIN 48 will not have a significant impact on our results of operations.
Regulation - Our intrastate natural gas transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. Other transportation activities are subject to regulation by the FERC. Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance contained in Statement 71, “Accounting for the Effects of Certain Types of Regulation.” During the rate-making process, regulatory authorities may require us to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions of the regulatory authorities could have an affect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomes no longer subject to the provisions of Statement 71, a write-off of regulatory assets and stranded costs may be required.
At December 31, 2006, we had regulatory assets in the amount of $399.2 million, included in other assets on our 2006 Consolidated Balance Sheet. Regulatory assets are being recovered through various rate cases with the exception of an immaterial amount, which we expect to eventually recover.
Asset Retirement Obligations - Statement 143, “Accounting for Asset Retirement Obligations” applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Statement 143 requires that we recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and amortization expense is immaterial to our consolidated financial statements.
In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation, depletion and amortization. These removal costs are non-legal obligations as defined by Statement 143. However, these non-legal asset
removal obligations should be accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities which have jurisdiction over our regulated operations have not required us to track this amount; rather these costs are addressed prospectively as depreciation rates are set in each general rate order. We have made an estimate of our removal cost liability using current rates since the last general rate order in each of our jurisdictions. However, significant uncertainty exists regarding the ultimate determination of this liability pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory authorities and the liability may be adjusted as more information is obtained. We have reclassified the estimated non-legal asset removal obligation from accumulated deprecation, depletion and amortization to non-current liabilities in other deferred credits on our Consolidated Balance Sheets as of December 31, 2006 and 2005. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation, depletion and amortization and other deferred credits and thus will not have an impact on earnings.
Share-Based Payment - In December 2004, the FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as we have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R.
The following table sets forth the effect on net income and earnings per common share (EPS) as if we had applied the fair-value recognition provisions of Statement 123 to stock-based employee compensation in the periods presented. The impact for 2006 was not material.
Earnings per Common Share - Basic EPS is calculated based on the daily weighted average number of shares of common stock outstanding during the period. Diluted EPS is calculated based on the daily weighted average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For any fiscal year period consisting of two or more quarters, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.
Labor Force - We employed 4,545 people at December 31, 2006. Approximately 17 percent of the workforce, all of whom are employed by Kansas Gas Service, are covered by collective bargaining agreements, with 10 percent covered by agreements that expire in 2009 and 7 percent covered by agreements that expire in 2010.
Use of Estimates - Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas received but for which no invoice has been received, provision for income taxes including
any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of our assets and liabilities, revenues and expenses, and related disclosures are necessarily affected by these estimates.
We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.
Reclassifications - Certain amounts in prior period consolidated financial statements have been reclassified to conform to the 2006 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
Other
In September 2006, the SEC staff issued SAB Topic 1N, “Financial Statements-Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how to quantify the effect of an error on the financial statements. SAB 108 is effective for our fiscal year ended December 31, 2006. We have completed our review of the applicability of SAB 108 to our operations and have determined that it did not have an impact on our consolidated financial statements.
Also in September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
B. ACQUISITIONS AND DIVESTITURES
Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction and will operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $216 million excluding AFUDC to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and federal regulatory authorities.
ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent.
Disposition of 20 percent interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline in April 2007. Under Statement 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary is not consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. Beginning January 1, 2006, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method. TransCanada paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.
Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was retroactive to January 1, 2006.
Disposition of Spring Creek - In October 2005, we entered into an agreement to sell our Spring Creek power plant in Oklahoma to Westar Energy, Inc. for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The financial information related to the properties sold is reflected as a discontinued component in our consolidated financial statements. All periods presented have been restated to reflect the discontinued component. See Note C for additional information.
Disposition of Production Segment - In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. The financial information related to the properties sold is reflected as a discontinued component in our consolidated financial statements. All periods presented have been restated to reflect the discontinued component. See Note C for additional information.
Acquisition of Koch Industries Natural Gas Liquids Business - In July 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, LP’s entire Mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., now Chisholm Pipeline Holdings, L.L.C., which has a 50 percent ownership interest in Chisholm Pipeline Company; MBFF, L.P., now ONEOK MBI, L.P., which owns an 80 percent interest in a 160,000 barrel per day fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, L.L.C., now ONEOK Vesco Holdings, L.L.C., an entity that owns a 10.2 percent interest in VESCO. These assets are included in our consolidated financial statements beginning on July 1, 2005.
The unaudited pro forma information in the table below presents a summary of our consolidated results of operations as if the acquisition of the Koch natural gas liquids businesses had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future.
The acquisition increased our Mid-Continent operating focus through a downstream extension of our natural gas gathering and processing operation. The assets acquired provide commercial, operational and administrative synergies as these assets enhance our existing mid-stream operating areas. This acquisition created new and expanded commercial opportunities and
we anticipate volumes and margins of our existing business to increase. Our gathering and processing assets are the second largest producer of NGLs on the natural gas liquids pipeline, storage and fractionation system, and all but two of our processing plants are connected to this system. Additionally, the acquisition improves our market access to the largest natural gas liquids hub, which is located on the Gulf Coast. As a result of our purchase price allocation, we assigned $1.2 billion to identifiable assets, consisting of approximately $928.9 million to tangible assets based on the fair value of the net assets and approximately $306.7 million to identifiable intangible assets, primarily contracts acquired, that will be amortized on a straight-line basis over an aggregated weighted average period of 40 years. The excess of the purchase price over the fair value of identifiable assets acquired, net of liabilities assumed is $173.9 million, which is recorded as goodwill. This entire amount of goodwill is deductible for tax purposes. The pro forma balance sheet as of the acquisition date is shown below.
Acquisition of Northern Plains - In November 2004, we acquired Northern Plains, now known as ONEOK Partners GP, which then owned 82.5 percent of the general partner interest and approximately 500,000 limited partnership units, together representing a 2.73 percent ownership interest, in Northern Border Partners, L.P., now known as ONEOK Partners, from CCE Holdings, LLC for $175 million.
Other - In December 2005, we sold our natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $527.2 million and recorded a pre-tax gain of $264.2 million, which is included in gain on sale of assets in our operating income. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold.
In 2004, we sold other assets including natural gas transmission and gathering pipelines, compression facilities, propane operations and a gas distribution system for an aggregate amount of approximately $20.4 million and recorded a pre-tax gain of $10.4 million.
C. DISCONTINUED OPERATIONS
In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors authorized management to pursue the sale in July 2005, which resulted in our former production segment being classified as held for sale beginning July 1, 2005.
Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. We subsequently entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators.
These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our financial statements and related notes for all periods shown relating to our former production segment and our power generation business are reflected as discontinued operations.
The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated.
The following table discloses the major classes of discontinued assets and liabilities included on our 2005 Consolidated Balance Sheet.
D. ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS
Risk Policy and Oversight - Market risks are monitored by our risk control group that operates independently from the operating segments that create or actively manage these risk exposures. The risk control group ensures compliance with our risk management policies.
We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. Our risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price and credit risk management, and marketing and trading activities. The committee also monitors risk metrics including value-at-risk (VAR) and mark-to-market losses. We have a corporate risk control organization led by our vice president of audit, business development and risk control, who is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.
To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. As a result, we cannot predict with precision the impact risk management decisions may have on our business, operating results or financial position.
Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities.” Under Statement 133, entities are required to record all derivative instruments at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered “held for trading purposes” as energy trading revenues, net and derivative instruments considered not “held for trading purposes” as cost of sales and fuel in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness, which is reported in earnings during the period the ineffectiveness occurs. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings.
As required by Statement 133, we formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.
EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3,” provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts.
At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter of 2004, we managed our Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.
Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF 03-11. For derivative instruments considered held for trading purposes that result in physical delivery, the indicators in EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.
For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
Energy Marketing and Interest Rate Risk Management Activities - Our operating results are affected by commodity price fluctuations. We routinely enter into derivative financial instruments to minimize the risk of commodity price fluctuations related to anticipated sales of natural gas and crude oil, purchase and sale commitments, fuel requirements, currency exposure, transportation and storage contracts, and natural gas and NGL inventories. We are also subject to the risk
of interest rate fluctuations in the normal course of business. We manage interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps.
Our Energy Services segment includes our wholesale and retail natural gas marketing and financial trading operations. Our Energy Services segment generally attempts to manage the commodity risk of our fixed-price physical purchase and sale commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of derivative instruments. With respect to the net open positions that exist within our financial trading operations, fluctuating commodity market prices can impact our financial position and results of operations, either favorably or unfavorably. The net open positions are actively managed and the impact of the changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.
Operating margins associated with our ONEOK Partners segments’ natural gas gathering, processing and fractionation activities are sensitive to changes in natural gas, condensate and NGL prices, principally as a result of contractual terms under which natural gas is processed and products are sold. ONEOK Partners uses physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products.
Fair Value Hedges - In prior years, we and ONEOK Partners terminated various interest rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2006 for all terminated swaps was $10.1 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
Currently, $490 million of fixed-rate debt is swapped to floating. Interest on the floating-rate debt is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through December 31, 2006, the weighted average interest rate on the $490 million of debt increased from 6.64 percent to 7.18 percent. At December 31, 2006, we recorded a net liability of $13.5 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $13.5 million to recognize the change in the fair value of the related hedged liability. See Note I for additional discussion of long-term debt.
Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded to cost of sales and fuel. The ineffectiveness related to these hedges was $9.0 million in 2006 and was not material in 2005 or 2004.
Cash Flow Hedges - Our Energy Services segment uses futures and swaps to hedge the cash flows associated with our anticipated purchases and sales of natural gas and cost of fuel used in transportation of natural gas. Accumulated other comprehensive income (loss) at December 31, 2006, includes gains of approximately $96.0 million, net of tax, related to these hedges that will be realized within the next 29 months as the hedges settle. If prices remain at current levels, we will recognize $109.0 million in net gains over the next 12 months, and we will recognize net losses of $13.0 million thereafter. In accordance with Statement 133, the actual losses that are reclassified into earnings will be based on the referenced floating price at each designated pricing period, along with the realization of the gains or losses on the related physical volumes, which are not reflected in the amounts above.
Our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas, NGLs and condensate. If prices remain at current levels, our ONEOK Partners segment will recognize $1.0 million in net losses, all of which will be recognized over the next 12 months.
Our Distribution segment also uses derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At December 31, 2006, Kansas
Gas Service and Texas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 2.0 Bcf, and 0.6 Bcf, respectively, which represents part of its gas purchase requirements for the 2006/2007 winter heating months.
Net gains and losses related to the ineffective portion of our hedges are reclassified out of accumulated other comprehensive income (loss) to operating revenues or cost of sales and fuel in the period the ineffectiveness occurs. Ineffectiveness related to these cash flow hedges was approximately $15.0 million, $33.9 million and $12.3 million in 2006, 2005 and 2004, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive income (loss) in 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur. There were no losses in 2006 or 2005 due to the discontinuance of cash flow hedge treatment.
Fair Value - The following table represents the fair value or carrying value of our energy marketing and interest rate risk management assets and liabilities for the periods indicated.
Based on quarterly measurements, the average fair values during 2006 for financial trading and non-trading assets and liabilities were approximately $49.0 million and $62.0 million, respectively. For 2005, the amounts were $443.6 million and $433.0 million, respectively.
Fair value estimates consider the market in which the transactions are executed. We utilize third party references for pricing points from NYMEX and third-party over-the-counter brokers to establish commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective of current market prices. Fair values are subject to change based on valuation factors. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.
Credit Risk - We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty.
Our counterparties consist primarily of financial institutions, major energy companies, local distribution companies (LDCs), electric utilities, and commercial and industrial end-users. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
Financial Instruments - The following table represents the carrying amounts and estimated fair values of our financial instruments for the periods indicated, excluding energy marketing and interest rate risk management assets and liabilities, which are listed in the table above.
The approximate fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, and notes payable, is book value due to their short-term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to us for debt with similar terms and remaining maturities.
At December 31, 2006, our investment securities classified as available-for-sale had an aggregate fair value of $22.4 million. We recorded $12.6 million in accumulated other comprehensive income (loss) for net unrealized holding gains on available-for-sale securities in 2006. For 2006, no gains or losses related to available-for-sale securities were reclassified to earnings from other comprehensive income (loss). We had no material securities classified as available-for-sale at December 31, 2005 and 2004.
E. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Carrying Amounts - The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
2006 Activity - Goodwill additions for 2006 in our ONEOK Partners segment include $7.5 million related to the consolidation of Guardian Pipeline, of which $5.7 million relates to the purchase of the 66-2/3 percent interest not previously owned by ONEOK Partners, and $2.1 million related to the incremental 1 percent acquisition in an affiliate that was
previously accounted for under the equity method. Following ONEOK Partners’ acquisition of the additional 1 percent interest, we began consolidating the entity.
Goodwill increased by approximately $27.9 million relating to ONEOK Partners’ 2003 acquisition of Viking Gas Transmission. In accounting for the acquisition, the entire purchase price was allocated to the fair value of the tangible assets including plant in service. Since that date, we have determined that the amount of purchase price representing a premium over Viking Gas Transmission’s historic rate base is not being recovered in its rates and, accordingly, should be accounted for as goodwill under Statement 142.
Goodwill adjustments for 2006 in our ONEOK Partners segment include an $8.4 million reduction related to the Black Mesa Pipeline impairment, offset by $6.4 million in purchase price adjustments.
In accordance with EITF 04-5, we consolidated our ONEOK Partners segment beginning January 1, 2006. The adoption of EITF 04-5 resulted in $152.8 million of ONEOK Partners’ goodwill being included on our 2006 Consolidated Balance Sheet and $32.0 million of goodwill that was previously recorded as our equity investment in ONEOK Partners.
2005 Activity - Goodwill additions for 2005 resulted from the acquisition of the natural gas liquids businesses owned by Koch in July 2005. See Note B for additional information regarding this acquisition.
The 2005 adjustment to goodwill resulted from the sale of our natural gas gathering and processing assets located in Texas by our ONEOK Partners segment.
Equity Method Goodwill - For the investments we account for under the equity method of accounting, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Equity method goodwill included in our investment in unconsolidated affiliates on our Consolidated Balance Sheets for 2006 and 2005 was $185.6 million and $33.4 million, respectively.
Intangible Assets
Our ONEOK Partners segment had $450.7 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2006, that consisted of $295.2 million related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch which is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life. The aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. Amortization expense for intangible assets for the years ended December 31, 2006 and 2005 was $7.7 million and $3.8 million, respectively. The following table reflects the gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 and 2005.
The adoption of EITF 04-5 resulted in the addition of $123.0 million of intangible assets, which was previously recorded as our equity investment in ONEOK Partners. An additional $32.5 million was recorded related to the general partner incentive distribution rights acquired through the purchase of the remaining 17.5 percent of the general partner interest from TransCanada. These intangible assets have an indefinite life; accordingly, they are not subject to amortization but are subject to impairment testing.
Impairment Test
We adopted Statement 142, “Goodwill and Other Intangible Assets,” on January 1, 2002, with a January 1 annual goodwill impairment testing date. In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. Prior to the change we had segments, and companies within segments, performing the annual goodwill impairment test as of the fourth quarter and as of January 1. The multiple testing dates were the result of:
•
the consolidation of ONEOK Partners, in accordance with EITF 04-5, which had a fourth-quarter annual goodwill impairment testing date;
•
our sale of certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners in April 2006, which resulted in the ONEOK Partners segment including assets with two impairment testing dates since our former gathering and processing and pipelines and storage segments used a January 1 testing date, while all the legacy ONEOK Partners assets used a fourth quarter testing date; and
•
our former natural gas liquids segment was comprised of assets primarily acquired in a July 2005 acquisition from Koch and due to the recent acquisition, no date had been selected for testing.
We believe that this change in accounting principle is preferable because (1) the test would be performed at the same time for all our segments, (2) performing the test as of the first day of the third quarter allows adequate time to complete the test while still providing time to report the impact of the test in our periodic filings for the third quarter, and (3) the third quarter is outside the normal operating cycle of most of our segments and coincides with our annual budget process, which results in more detailed budgeting and forecasting information available for use in the impairment analysis. There were no impairment charges resulting from the July 1, 2006, impairment testing, and no events indicating an impairment has occurred subsequent to that date.
F. COMPREHENSIVE INCOME
The tables below show the gross amount of other comprehensive income (loss) and related tax (expense) or benefit for the periods indicated.
The table below shows the balance in accumulated other comprehensive income (loss) for the periods indicated. See Note J for more information regarding the adoption of Statement 158.
G. CAPITAL STOCK
Series A Convertible Preferred Stock - There are no shares of Series A currently outstanding.
Series B Convertible Preferred Stock - There are no shares of Series B currently outstanding.
Series C Preferred Stock - Series C Preferred Stock (Series C) is designed to protect our shareholders from coercive or unfair takeover tactics. Holders of Series C are entitled to receive, in preference to the holders of ONEOK Common Stock, quarterly dividends in an amount per share equal to the greater of $0.50 or, subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount (payable in kind) of all non-cash dividends. No Series C has been issued.
Common Stock - At December 31, 2006, we had approximately 173 million shares of authorized and unreserved common stock available for issuance.
Stock Repurchase Plan - A total of 15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005 to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. During 2005, we repurchased 7.5 million shares of our common stock pursuant to this plan. On August 7, 2006, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million, which completed the plan approved by our Board of Directors. Under the terms of the accelerated repurchase agreement, we repurchased 7.5 million shares immediately from UBS. UBS then borrowed 7.5 million of our shares and will purchase shares in the open market to settle its short position. Our repurchase is subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment can be settled, at our option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to ONEOK common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” In February 2007, the forward purchase contract settled for a cash payment of $20.1 million, which was recorded in equity. We have no remaining shares authorized for repurchase under our stock repurchase plan.
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2006, May 1, 2006, July 31, 2006, and October 31, 2006, were $0.28 per share, $0.30 per share, $0.32 per share and $0.32 per share, respectively. Additionally, a quarterly dividend of $0.34 per share was declared in January 2007, payable in the first quarter.
Equity Units - On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock for each equity unit they owned. The number of shares that we issued for each stock purchase contract was determined based on our average closing price over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.
2004 Common Stock Offering - During the first quarter of 2004, we sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.
H. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE
General - The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. Our commercial paper and short-term notes payable, excluding ONEOK Partners’ short-term notes payable, carried average interest rates of 4.66 percent and 3.73 percent for 2006 and 2005, respectively. ONEOK Partners’ short-term notes payable carried an average interest rate of 5.79 percent for 2006.
ONEOK Short-Term Bridge Financing Agreement - On July 1, 2005, we borrowed $1.0 billion under a new short-term bridge financing agreement to assist in financing our acquisition of assets from Koch. See Note B for additional information
about this acquisition. We funded the remaining acquisition cost through our commercial paper program. During 2006, we repaid the facility in full, and it was terminated according to its terms.
ONEOK Five-Year Credit Agreement - In April 2006, we amended our 2004 $1.2 billion five-year credit agreement to accommodate the transaction with ONEOK Partners. This amendment included changes to the material adverse effect representation, the burdensome agreement representation and the covenant regarding maintenance of control of ONEOK Partners.
In July 2006, we amended and restated our 2004 $1.2 billion five-year credit agreement. The amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million. The interest rates applicable to extensions of credit under this agreement are based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings.
Under the five-year credit agreement, we are required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
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a $500 million sublimit for the issuance of standby letters of credit,
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a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter,
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a requirement that we maintain the power to control the management and policies of ONEOK Partners, and
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a limit on new investments in master limited partnerships.
The debt covenant calculations in our five-year credit agreement exclude the debt of ONEOK Partners. At December 31, 2006, we had no borrowings outstanding under this agreement.
Our five-year credit agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of our businesses, transactions with affiliates, the use of proceeds and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends. At December 31, 2006, we were in compliance with these covenants.
At December 31, 2006, we had no commercial paper or short-term notes payable outstanding. Commercial paper and short-term notes payable totaling $1.54 billion were outstanding at December 31, 2005, which included $900.0 million of bridge financing for the Koch assets acquisition. We had $58.5 million and $178.7 million in letters of credit outstanding at December 31, 2006 and 2005, respectively.
ONEOK Uncommitted Line of Credit - We have a credit agreement with a commercial bank that gives us access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $15 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Federal Funds overnight rate, which is the rate that banks charge each other for the overnight borrowing of funds. This agreement remains in effect until canceled by the commercial bank or us. This agreement does not contain any covenants more restrictive than those in our $1.2 billion five-year credit agreement. This credit agreement is used to issue a $15.0 million standby letter of credit.
2006 Partnership Credit Agreement - In December 2006, ONEOK Partners amended its 2006 Partnership Credit Agreement. This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA (net income before interest expense, income taxes, and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland Pass Pipeline Company agreement from the covenant that limits ONEOK Partners’ ability to enter into agreements that restrict its ability to grant liens to the lenders under the 2006 Partnership Credit Agreement.
In March 2006, we amended and restated the 2005 revolving credit agreement with certain financial institutions and increased the term for an additional five years, increased the facility to $750 million from $500 million, and lowered the pricing. The 2005 revolving credit agreement, as amended and restated, is referred to as the 2006 Partnership Credit Agreement.
Under the 2006 Partnership Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
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maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1, and
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maintaining a ratio of EBITDA to interest expense of greater than 3 to 1.
If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement may become immediately due and payable. At December 31, 2006, ONEOK Partners was in compliance with these covenants. At December 31, 2006, a $10 million letter of credit was outstanding under the 2006 Partnership Credit Agreement. The letter of credit expires May 1, 2007.
ONEOK Partners Bridge Facility - In April 2006, ONEOK Partners entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate of banks and borrowed $1.05 billion under this agreement to finance a portion of its purchase of certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments. In September 2006, ONEOK Partners repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated according to its terms. See Note I for further discussion regarding the issuance of senior notes.
I. LONG-TERM DEBT
The following table sets forth our long-term debt for the periods indicated.
The aggregate maturities of long-term debt outstanding for the years ending December 31, 2007, through 2011 are shown below.
Additionally, $184.3 million of our debt is callable at par at our option from now until maturity, which is 2019 for $92.6 million and 2028 for $91.7 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.
ONEOK Partners Debt Issuance - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the 2012 Notes), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the 2016 Notes) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the 2036 Notes and collectively with the 2012 Notes and the 2016 Notes, the Notes). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a registration statement filed on September 19, 2006. The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.
ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses, but before offering expenses, were used to repay all of the amounts outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and sell and lease back its property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016, and October 1, 2036, respectively. ONEOK Partners will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Guardian Pipeline Senior Notes - ONEOK Partners’ acquisition of the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners resulted in the inclusion of $145.6 million of long-term debt on our 2006 Consolidated Balance Sheet. These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.86 percent.
Guardian Pipeline’s senior notes contain financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and
payable immediately. Beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1. At December 31, 2006, Guardian Pipeline was in compliance with its financial covenants.
ONEOK - In November 2005, we elected for the early redemption of our 7.75 percent $300.0 million long-term notes with a stated maturity of August 2006. The early redemption occurred in December 2005, for a total payment of $314.4 million. In addition to the principal payment, we were required to pay a make-whole call premium of $5.7 million and accrued interest of $8.7 million. We funded this early redemption with the proceeds from the sale of our natural gas gathering and processing assets located in Texas.
In June 2005, we issued $800 million of notes, comprised of $400 million in 10-year maturities with a coupon of 5.2 percent and $400 million in 30-year maturities with a coupon of 6.0 percent. Proceeds from this debt issuance were used to repay commercial paper borrowings and for general corporate purposes.
In March 2005, we had $335 million of long-term debt mature. We funded payment of this debt with working capital and the issuance of commercial paper in the short-term market.
In the first quarter of 2003, we issued long-term debt concurrent with our public equity offering. We issued a total of 16.1 million equity units at the public offering price of $25 per unit, for a total of $402.5 million. Each equity unit consisted of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carried a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes was recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there was no impact on earnings as this liability was paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense associated with the discounting was approximately $3.5 million over three years. In November 2005, we remarketed the notes with a new rate of 5.51 percent. The notes continue to have a stated maturity of February 2008. The cash received was put into a treasury portfolio pledged as collateral against the purchase contracts. We received this cash on February 16, 2006, when we successfully settled our equity units. See further discussion in Note G.
J. EMPLOYEE BENEFIT PLANS
Retirement and Other Postretirement Benefit Plans
Retirement Plans - We have defined benefit and defined contribution retirement plans covering substantially all employees. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a profit-sharing plan. Certain officers and key employees are also eligible to participate in supplemental retirement plans. We generally fund pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974.
The accumulated benefit obligation for the defined benefit pension plan and supplemental retirement plan was $767.3 million and $704.4 million at December 31, 2006 and 2005, respectively.
Other Postretirement Benefit Plans - We sponsor welfare plans that provide postretirement medical benefits and life insurance benefits to substantially all employees who retire under the retirement plans with at least five years of service. The postretirement medical plan is contributory, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance. Nonbargaining unit employees retiring between the ages of 50 and 55, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers (IBEW) hired after June 30, 2003, and gas union employees hired after July 1, 2004, who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Non-bargaining unit and IBEW retirees may qualify for medical insurance premium reimbursements from us. These reimbursements will be applied toward Medicare Part D and B premiums paid by the retiree. We have developed a wrap-around plan to be applied to the Medicare Part D program for the remaining bargaining unit retirees.
Measurement - We use a September 30 measurement date for the majority of our plans.
Statement 158 - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” which was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will not go into effect until our year ending December 31, 2008. Statement 158 requires us to recognize the overfunded or underfunded status of our plans as an asset or liability on our 2006 Consolidated Balance Sheet and to recognize changes in that funded status in accumulated other comprehensive income (loss) in the year in which the changes occur.
The following table illustrates the incremental effect of the adoption of Statement 158 on our financial statements at December 31, 2006.
Regulatory Treatment - The OCC, KCC, and regulatory authorities in Texas have approved the recovery of pension costs and other postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for pension and postretirement costs. Differences, if any, between the expense and the amount recovered through rates are charged to earnings.
The table below sets forth the amounts in accumulated other comprehensive income (loss) following the adoption of Statement 158 that have not yet been recognized as components of net periodic benefit expense.
Obligations and Funded Status - The following tables set forth our pension and other postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated.
There are no plan assets expected to be withdrawn and returned to us in the coming year.
Components of Net Periodic Benefit Cost
The following tables set forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated.
The following table sets forth the amounts recognized in either accumulated other comprehensive income (loss) regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year.
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for the periods indicated.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated.
Our overall expected long-term rate of return on plan assets assumption is an equally weighted blend of historical return, building block and economic growth/yield to maturity projections that we determined based on discussions with our independent investment consultants.
Our discount rates for 2006 are based on matching the amount and timing of the projected benefit payments to a spot-rate yield curve, which provides zero coupon interest rates into the future. The methodology for developing the yield curve includes selecting the bonds to be included (only bonds rated Aa by Moody’s, excluding callable bonds, bonds with less than a minimum issue size, yield “outliers,” and various other filtering criteria to remove unsuitable bonds). Once the bonds are selected, a best-fit regression curve to the bond data is determined, modeling yield-to-maturity as a function of years to maturity. This coupon yield curve is converted to a spot yield curve using the calculation technique which assumes the price of a coupon bond for a given maturity equals the present value of the underlying bond cash flows using zero coupon spot rates. Once the yield curve is developed, the projected cash flows for the plan for each year in the future are calculated. These projected cash flows values are based on the most recent valuation. Each annual cash flow of the plan obligations is discounted using the yield at the appropriate point on the curve, and then the single equivalent discount rate that would yield the same value for the cash flow is determined.
Prior to the adoption of Statement 158 at December 31, 2006, our discount rates were based on our bond model analysis, where the amount and timing of the projected benefit payments are matched with the cash payments from coupons and maturities of a hypothetical bond portfolio. We first determined the projected cash flows for the plan for each year in the future. We projected these values based on the most recent valuation. The longest maturity period for bonds considered in our model was 30 years. Since cash flows are expected to continue beyond this period of time, we discounted all benefit cash flows over 30 years back to the 30th year at a rate that was consistent with the yields on long-term zero coupon bonds. The resulting present value was treated as an additional benefit cash flow for the 30th year and handled the same way as any other benefit cash flow within our bond matching process. Our model used the universe of bonds available at the measurement date with a quality rating of AA or better as rated by Moody’s or S&P. Callable bonds were generally eliminated from the universe. A regression curve was generated for the expected yields from the remaining bonds. Any bonds with yields that fall outside a two standard deviation corridor were eliminated. Using the projected benefit cash flows and the bond universe defined above, our model considered all possible bond portfolios that produced matching cash flows and used linear programming techniques to select the optimal portfolio with the highest possible yield. Our methodology was such that no single bond could comprise more than 15 percent of the total purchase. The model permitted bond cash flows for a particular year to exceed the benefit cash flow for that year. The excess for a given year was used to meet the benefit cash flow in a future year and was reinvested at the one year forward rates.
Health Care Cost Trend Rates - The following table sets forth the assumed health care cost trend rates for the periods indicated.
Assumed health care cost trend rates have a significant effect on the amounts reported for our health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects.
Plan Assets - The following table sets forth our pension and postretirement benefit plan weighted-average asset allocations as of the measurement date.
Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term investment fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. The plan’s investments include a diverse blend of various U.S. and international equities, venture capital, investments in various classes of debt securities, and insurance contracts. The target allocation for the plan assets of our pension plan is as follows.
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.
Contributions - For 2006, $1.8 million and $2.5 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. Additionally, we made benefit payments for our postretirement benefit plan of $11.4 million in 2006. We presently anticipate our total 2007 contributions will be $5.0 million for the pension plan and $13.4 million for the other postretirement benefit plan. Additionally, the expected benefit payments for our postretirement benefit plan are estimated to be $15.4 million.
Pension and Other Postretirement Benefit Payments - The following table sets forth the pension benefits and postretirement benefit payments expected to be paid in 2007-2016.
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2006, and include estimated future employee service.
Other Employee Benefit Plans
Thrift Plan - We have a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, we match employee contributions. The cost of the plan was $12.8 million, $10.5 million and $10.4 million in 2006, 2005 and 2004, respectively.
Profit Sharing Plan - We have a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004. We plan to make a contribution to the profit sharing plan each quarter equal to 1 percent of each participant’s compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. The cost of the plan was $1.6 million and $0.6 million in 2006 and 2005, respectively.
K. COMMITMENTS AND CONTINGENCIES
Leases - The initial lease term of our 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, we can purchase the property at its fair market value. Annual rent expense for the lease will be approximately $6.8 million until 2009. Rent payments were $9.3 million in 2006, 2005 and 2004. Estimated future minimum rental payments for the lease are $9.3 million for each of the years ending December 31, 2007 through 2009.
We have the right to sublet excess office space in ONEOK Plaza. We received rental revenue of $2.9 million in 2006, 2005 and 2004. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.5 million in 2007, $2.4 million in 2008, $1.8 million in 2009 and $0.8 million in 2010 and 2011.
Our operating leases include a gas processing plant, office buildings, vehicles and equipment. The following table sets forth the future minimum lease payments as of December 31, 2006, under non-cancelable operating leases for each of the following years.
The amounts in the ONEOK column above include the following minimum lease payments relating to the lease of a gas processing plant for which we have a liability as a result of uneconomic lease terms: $24.2 million in 2007, $24.2 million in 2008, $24.0 million in 2009, $24.2 million in 2010 and $30.6 million in 2011. The liability is accreted to rent expense in the amount of $13.0 million per year over the term of the lease; however, the cash outflow under the lease remains the same.
Environmental Liabilities - We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have commenced remediation on 11 sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, have commenced soil remediation at an additional site, and we expect to commence soil remediation on the other two sites in 2007. We have begun site assessment at the remaining site where no active remediation has occurred.
To date, we have incurred remediation costs of $6.0 million and have accrued an additional $6.0 million related to the sites where we have commenced or will soon commence remediation. The $6.0 million estimate of future remediation costs for
these sites is based on our environmental assessments and remediation plans approved to date by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.
Yaggy Facility - In January 2001, our Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchinson, Kansas. In July 2002, the KDHE issued an administrative order that assessed a civil penalty against us, based on alleged violations of several KDHE regulations. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order required us to conduct an environmental remediation and a geoengineering study. The required environmental remediation has been completed. Work continues on the geoengineering study. We will begin injecting brine into the facility in the first quarter of 2007 in order to ensure the long-term integrity of the facility until its future use is determined. Based on information currently available to us, we do not believe there are any material adverse effects resulting from the Consent Order.
In February 2004, a jury awarded approximately $1.7 million in actual damages to the plaintiffs in a lawsuit involving property damage alleged to relate to the natural gas explosions and eruptions in Hutchinson, Kansas. In April 2004, the judge in this case awarded punitive damages against Mid-Continent Market Center, L.L.C. in the amount of $5.25 million. We filed an appeal of the jury verdict and the punitive damage award. In August 2004, the appeal was transferred to the Kansas Supreme Court. On June 16, 2006, the Kansas Supreme Court affirmed the punitive damage award of $5.25 million against Mid-Continent Market Center. Further the Court held that (i) ONEOK and Mid-Continent Market Center were entitled to set off the amount paid to the plaintiff’s insurance companies in settlement; and (ii) the plaintiffs were entitled to recover attorney fees. The punitive damage award has been paid. On December 8, 2006, oral arguments were held before the Kansas District Court to address plaintiff’s attorney’s fees and setoff amounts paid by insurance carriers to the plaintiffs. The Kansas District Court took the issues under advisement. All remaining damages are insured. Based on information currently available to us, we believe our legal reserves and insurance coverage is adequate and that this matter will not have a material adverse effect on us.
The two class action lawsuits filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, our Yaggy facility in January 2001, resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5.0 million in actual damages, and the judge ordered the payment of approximately $2.0 million in attorney fees and $0.6 million in expenses, all of which are covered by insurance. In the other class action relating to business claims, the jury awarded no damages. The jury rejected claims for punitive damages in both cases. On April 11, 2005, the court denied the plaintiffs’ motion for a new trial and denied a post-trial motion filed by defendants. We filed our notice of appeal of the residential class verdict and the attorney fee award. The cases have now been transferred to the Kansas Supreme Court for appeal. With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.
Other - We are a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.
L. INCOME TAXES
The following table sets forth our provisions for income taxes for the periods indicated.
The following table is a reconciliation of our provision for income taxes for the periods indicated.
The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated.
With the exception of our ONEOK Partners segment, we had utilized all federal and state net operating loss carryforwards at December 31, 2006.
ONEOK Partners had available, at December 31, 2006, approximately $8.0 million of tax benefits related to net operating loss carryforwards, which will expire between the years 2022 and 2026. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.
At December 31, 2006, we had $3.7 million in deferred investment tax credits related to regulated operations recorded in other deferred credits, which will be amortized over the next nine years.
We had accrued income taxes payable of approximately $70.0 million and $113.8 million at December 31, 2006 and 2005, respectively.
M. SEGMENTS
Segment Descriptions - We have divided our operations into four reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (1) our ONEOK Partners segment gathers, processes, transports and stores natural gas; gathers, treats, stores, and fractionates NGLs; and provides NGL gathering and distribution services; (2) our Distribution segment delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (3) our Energy Services segment markets natural gas to wholesale and retail customers and markets electricity to a wholesale customer; and (4) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are regulated.
In September 2005, we completed the sale of our former production segment. Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. The transaction received FERC approval and was completed on October 31, 2006. These components of our business are accounted for as discontinued operations in accordance with Statement 144. Our production business is included in our Other segment in the tables below, while our power generation business is included in our Energy Services segment.
Accounting Policies - The accounting policies of the segments are described in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments.
Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5 and we elected to use the prospective method. In April 2006, we sold certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are now included in our ONEOK Partners segment. All periods presented have been restated to reflect this change.
Customers - The primary customers for our ONEOK Partners segment include major and independent oil and gas production companies, gathering and processing companies, petrochemical and refining companies, natural gas producers, marketers, industrial facilities, local distribution companies (LDCs) and electric power generating plants. Our Distribution segment provides natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. Our Energy Services segment buys and sells natural gas and power to LDCs, municipalities, producers, large industrials, power generators, retail aggregators and other marketing companies, as well as residential and small commercial/industrial companies.
In 2006 and 2005, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues. In 2004, we had one customer, BP PLC and affiliates (BP), from which we received $745.1 million, or approximately 13 percent of our consolidated revenues. Our Energy Services segment received $664.4 million of the total 2004 revenues received from BP, or approximately 11 percent of consolidated 2004 revenues.
Operating Segment Information - The following tables set forth certain selected financial information for our four operating segments for the periods indicated.
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $300.2 million, net margin of $252.0 million and operating income of $237.4 million, including $113.9 million from a gain on sale of assets, for the year ended December 31, 2006.
(b) - All of our Distribution segment’s operations are regulated.
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $168.1 million, net margin of $118.3 million and operating income of $54.9 million for the year ended December 31, 2005.
(b) - All of our Distribution segment’s operations are regulated.
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $105.0 million, net margin of $68.9 million and operating income of $24.2 million for the year ended December 31, 2004.
(b) - All of our Distribution segment’s operations are regulated.
N. QUARTERLY FINANCIAL DATA (UNAUDITED)
Total operating revenues are consistently greater during the heating season from November through March due to the large volume of natural gas sold to customers for heating. The following tables set forth the unaudited quarterly results of operations for the periods indicated.
The first quarter 2006 amounts in the above table have been restated to reflect the consolidation of ONEOK Partners in accordance with EITF 04-5. This restatement impacted all amounts except net income and earnings per share. See Note A for discussion of EITF 04-5.
O. SUPPLEMENTAL CASH FLOW INFORMATION
The following table sets forth supplemental information relative to our cash flow for the periods indicated.
Cash paid (received) for interest includes swap terminations, treasury rate-lock terminations and ineffectiveness of $22.6 million and $(82.9) million for the years ended December 31, 2005 and 2004, respectively.
P. STOCK-BASED COMPENSATION
Deferred Compensation Plans
Employee Deferred Compensation Plan - The 2005 Employee Deferred Compensation Plan (the 2005 Deferred Compensation Plan) provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides non-qualified deferred compensation benefits which are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Under the plan, participants have the option to defer a portion of their salary and/or bonus compensation to a short-term deferral account, which pays out a minimum of five years from commencement, or a long-term deferral account, which pays out at retirement or termination of the participant’s employment. Participants are immediately 100 percent vested with respect to all deferrals under the plan. Short-term deferral accounts are credited with a deemed investment return based on the five-year treasury bond fund. Long-term deferral accounts are credited with a deemed investment return based on various investment options. At the distribution date, cash is distributed to participants based on the fair market value of the deemed investment of the participant account at that date. The 2005 Deferred Compensation Plan contains provisions intended to comply with the requirements of Section 409A of the Internal Revenue Code. Those provisions relate to participant elections to defer compensation, the timing of payments and distributions and prohibition of any foreign trust for the 2005 Deferred Compensation Plan.
Deferred Compensation Plan for Non-Employee Directors - The ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors provides our directors, who are not our employees, the option to defer all or a portion of their compensation for their service on our Board of Directors. Under the plan, directors may elect either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer and/or meeting fees, plus accrued interest. Under the phantom stock option, directors may defer all or a portion of their annual retainer and/or meeting fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan. Shares are distributed to non-employee directors at the fair market value of our common stock at the date of distribution.
Equity Compensation Plan
The ONEOK, Inc. Equity Compensation Plan (Equity Compensation Plan) provides for the granting of stock-based compensation, including incentive stock options, non-statutory stock options, stock bonus awards, restricted stock awards, restricted stock unit awards, performance stock awards and performance unit awards to eligible employees and the granting of stock awards to non-employee directors. We have reserved a total of approximately 3.0 million shares of common stock for issuance under the plan. The maximum number of shares for which options or other awards may be granted to any employee during any year is 500,000.
Options - Stock options may be granted that are not exercisable until a fixed future date or in installments. Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise the option within a period determined by the Executive Compensation Committee (the Committee) and stated in the option. In the event of death, the option may be exercised by the personal representative of the optionee within a period to be determined by the Committee and stated in the option. A portion of the options issued to date can be exercised after one year from grant date provided an option must be exercised no later than ten years after grant date.
Restricted Stock Awards - Restricted stock awards may be granted to key employees with ownership of the common stock vesting over a period determined by the Committee and stated in the award. Those granted to date vest over a three-year period. Compensation expense is recognized on a straight-line basis over the period of the award. Shares awarded may not be sold during the vesting period. Dividends on restricted stock awards are reinvested in common stock. Awards granted in 2003 vest over a three-year period and entitle the grantee to receive shares of our common stock. The equity awards are measured at fair value as if they were vested and issued on the grant date, adjusted for estimated forfeitures. Compensation expense is recognized on a straight-line basis over the period of the award.
Restricted Stock Incentive Units - Restricted stock incentive units may be granted to key employees with ownership of the common stock underlying the incentive unit vesting over a period determined by the Committee and stated in the award. Awards granted in 2006 vest over a three-year period and entitle the grantee to receive shares of our common stock. Awards granted in 2005 and 2004 entitle the grantee to receive two-thirds of the grant in our common stock (equity awards) and one-third of the grant in cash (liability awards). The equity awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments and adjusted for estimated forfeitures. The portion of the grants that
are settled in cash are classified as liability awards with fair value based on the fair market value of our common stock, reduced by expected dividend payments and adjusted for estimated forfeitures, at each reporting date. No dividends are paid on the restricted stock incentive units. Compensation expense is recognized on a straight-line basis over the period of the award.
Performance Unit Awards - Performance unit awards may be granted to key employees. The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Committee and stated in the award if certain performance criteria are met by us. Performance units granted to date vest at the expiration of a three-year period. Upon vesting, a holder of performance units is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance units granted based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of 20 other energy companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award with adjustments as needed based on our probable performance.
If paid, the performance unit awards granted in 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2006 performance unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for changes in forfeitures.
If paid the performance unit awards granted in 2005 and 2004 entitle the grantee to receive two-thirds of the grant in shares of our common stock (equity awards) and one-third of the grant in cash (liability awards), while awards granted in 2003 entitle the grantee to receive common stock only. These awards vest over a three-year period. The fair values of these performance units that are classified as equity awards were calculated as of the date of grant and remain fixed as equity units upon adoption of Statement 123R. The fair values of the one-third liability portion of the performance units are estimated at each reporting date based on a Monte Carlo model.
Stock Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock options, stock bonus awards, including performance unit awards, restricted stock awards, and restricted stock unit awards. Under the DSCP, these awards may be granted by the Committee at any time on or before January 18, 2011. We have reserved a total of 700,000 shares of common stock for issuance under the DSCP. The maximum number of shares of common stock which can be issued to a participant under the DSCP during any year is 20,000. No performance unit awards or restricted stock awards have been made to non-employee directors under the DSCP.
Options - Options may be exercisable in full at the time of grant or may become exercisable in one or more installments. Options must be exercised no later than ten years after the date of grant of the option. In the event of retirement or termination, the optionee may exercise the option within a period determined by the Committee. In the event of death, the option may be exercised by the personal representative of the optionee over a period of time determined by the Committee.
General
Effective January 1, 2006, we adopted Statement 123R. See Note A for additional information. For all awards outstanding, we used a forfeiture rate ranging from three to nine percent based on historical forfeitures under our share-based payment plans. We use a combination of issuances from treasury stock and repurchases in the open market to satisfy our share-based payment obligations.
Compensation cost expensed for our share-based payment plans described below was $28.8 million, $13.6 million and $14.8 million 2006, 2005 and 2004, respectively, net of a $11.2 million, $5.3 million and $5.6 million tax benefit, respectively. No compensation cost was capitalized for 2006, 2005 and 2004.
Cash received from the exercise of awards under all share-based payment arrangements was $5.6 million for 2006. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $3.9 million for 2006. No cash was used to settle awards granted under share-based payment arrangements.
Stock Option Activity
The total fair value of stock options vested during 2006, was $4.3 million. The following table sets forth the stock option activity for employees and non-employee directors for the periods indicated.
The aggregate intrinsic value in the table below represents the total pre-tax intrinsic value, based on our year-end closing stock price of $43.12, that would have been received by the option holders had all option holders exercised their options as of December 31, 2006.
The fair value of each restored option was estimated on the date of grant using the Black-Scholes model and the assumptions in the table below.
The expected life of outstanding options ranged from one to ten years based upon experience to date and the make-up of the optionees. As of December 31, 2006, the amount of unrecognized compensation cost related to nonvested stock options was not material. The following table sets forth various statistics relating to our stock option activity.
Restricted Stock Activity
The total fair value of shares vested during 2006 was $5.7 million. As of December 31, 2006, there was $3.1 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.1 year. The following tables set forth activity and various statistics for the restricted stock equity awards.
The following table sets forth activity for the restricted stock liability awards.
Performance Unit Activity
The total fair value of shares vested during 2006 was $4.9 million. As of December 31, 2006, there was $10.1 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized over a weighted-average period of 1.4 years. The following tables set forth activity and various statistics related to the performance unit equity awards and the assumptions used in the valuations of the 2006, 2005 and 2004 grants at the grant date.
The following tables set forth activity for the performance unit liability awards and the assumptions used in the valuations at the end of each period indicated.
Employee Stock Purchase Plan
The ONEOK, Inc. Employee Stock Purchase Plan (the ESPP) currently has 3.8 million shares reserved for issuance. Subject to certain exclusions, all full-time employees are eligible to participate. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan. The Committee may allow contributions to be made by other means, provided that in no event will contributions from all means exceed 10 percent of the employee’s annual base pay. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 63 percent of employees participated in the plan in both 2006 and 2005, while 54 percent of employees participated in 2004. Under the plan, we sold 340,364 shares at $22.57 in 2006, 289,558 shares at $22.57 per share in 2005, and 449,090 shares at $18.84 per share in 2004.
Employee Stock Award Program
Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $26 per share, and we have issued and will continue to issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. The total number of shares of our common stock available for issuance under this program is 200,000.
Shares issued to employees under this program totaled 40,705, 32,734 and 12,681 for the years ended December 31, 2006, 2005 and 2004, respectively. Compensation expense related to the Employee Stock Award Plan was $1.6 million, $1.1 million and $0.3 million in 2006, 2005 and 2004, respectively.
Q. UNCONSOLIDATED AFFILIATES
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated.
(a) - Beginning January 1, 2006, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method (Note B). For the first three months of 2006, ONEOK Partners included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, ONEOK Partners included 50 percent of Northern Border Pipeline’s income in equity earnings from investments.
(b) - Equity method goodwill (Note E) was $185.6 million and $33.4 million at December 31, 2006 and 2005, respectively.
(c) - ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering. As a result of the incentive, ONEOK Partners’ share of Lost Creek Gathering income exceeds the amount its 35 percent ownership interest.
(d) - ONEOK Partners was consolidated beginning January 1, 2006, in accordance with EITF 04-5. Prior to January 1, 2006, ONEOK Partners was accounted for as an investment under the equity method.
Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All 2006 amounts in the table below are equity earnings from investments in our ONEOK Partners segment.
Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.
R. EARNINGS PER SHARE INFORMATION
The following table sets forth the computation of basic and diluted EPS from continuing operations for the periods indicated.
There were 66,463, 28,107 and 17,734 option shares excluded from the calculation of diluted EPS for 2006, 2005 and 2004, respectively, since their inclusion would be antidilutive.
S. ONEOK PARTNERS
General Partner Interest - See Note B for discussion of the April 2006 acquisition of the additional general partner interest in ONEOK Partners. The limited partner units we received from ONEOK Partners were newly created Class B units which are presently subordinated to the common units with respect to the payment of the minimum quarterly distribution, which is $0.55 per unit, and thereafter, have the same right to receive minimum quarterly distributions as those received by the holders of the common stock. If distributions to all unitholders exceed $0.55 per unit, the holders of common units and the Class B units receive the same distribution per unit. Under the ONEOK Partners’ partnership agreement and in conjunction with the issuance of additional common units by ONEOK Partners, we, as the general partner, are required to make equity contributions in order to maintain our representative general partner interest.
Our investment in ONEOK Partners is shown in the table below for the periods presented.
Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash. Available cash generally consists of all cash receipts adjusted for cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98.0 percent to limited partners and 2 percent to the general partner. As an incentive, the general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the general partner receives:
•
15 percent of amounts distributed in excess of $0.605 per unit,
•
25 percent of amounts distributed in excess of $0.715 per unit, and
•
50 percent of amounts distributed in excess of $0.935 per unit.
ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership ownership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the general partner. The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated.
The quarterly distributions paid by ONEOK Partners to limited partners in the first, second, third and fourth quarters of 2006 were $0.80 per unit, $0.88 per unit, $0.95 per unit, and $0.97 per unit, respectively.
In January 2007, ONEOK Partners declared a cash distribution of $0.98 per unit payable in the first quarter. On February 14, 2007, we received the related incentive distribution of $10.6 million which is included in the table above.
Relationship - We own 45.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, the assets and cash flows from ONEOK Partners are restricted to us. Distributions are declared quarterly by ONEOK Partners based on the terms of its partnership agreement and we are restricted from the assets and cash flows except through these quarterly distributions. For the years ended December 31, 2006, 2005 and 2004, cash distributions declared from ONEOK Partners to us totaled $145.1 million, $10.8 million and $2.7 million, respectively. See Note M for more information on ONEOK Partners results.
Affiliate Transactions - We have certain transactions with our 45.7 percent owned ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its gathering and processing operations to our Energy Services segment. In addition, a large portion of ONEOK Partners’ revenues from its pipelines and storage operations are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ transportation and storage services.
As part of the transaction between us and ONEOK Partners, ONEOK Partners acquired contractual rights to process natural gas at the Bushton Gas Processing Plant (Bushton Plant) from us through a Processing and Services Agreement, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. In exchange for such services, ONEOK Partners pays us for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant. On January 1, 2007, the Bushton plant was temporarily idled. ONEOK Partners is in the process of adding new facilities and making other changes at the Bushton plant as part of its Overland Pass Pipeline Company project and associated expansions.
We provide a variety of services to our affiliates, including cash management and financing services, employee benefits provided through our benefit plans, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a benefit that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated through a modified Distrigas method, a method using a combination of ratios of gross plant and investment, operating income and wages.
The following table shows transactions with ONEOK Partners for the periods shown.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Under the supervision and with the participation of senior management, including our Chief Executive Officer (“Principal Executive Officer”) and our Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2006, to ensure the timely disclosure of required information in our periodic SEC filings.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2006.
Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).
Changes in Internal Controls Over Financial Reporting
We have made changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal year ended December 31, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as described below.
In connection with the sale of our former gathering and processing, natural gas liquids, and pipelines and storage assets to ONEOK Partners, the operations currently managed in ONEOK Partners’ Denver, Colorado, offices have been moved to Tulsa, Oklahoma, while the Omaha, Nebraska, office operations are anticipated to be completely transitioned to Tulsa by
April 2007. The majority of the financial reporting functions that have been moved were absorbed into our existing internal control structure. For the financial reporting functions that are moving from Omaha, the adaptation and modification of our internal control structure will continue into 2007.
In July 2005, we completed our acquisition of the Natural Gas Liquids assets that were subsequently transferred to our ONEOK Partners segment. As part of our integration activities that continued into 2006, we developed and incorporated new controls and procedures into our internal controls over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III.
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors of the Registrant
Information concerning our directors is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Executive Officers of the Registrant
Information concerning our executive officers is included in Part I, Item 1. Business, of this Annual Report on Form 10-K.
Compliance with Section 16(a) of the Exchange Act
Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Nominating Committee Procedures
Information concerning the nominating committee procedures is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Audit Committee
Information concerning the Audit Committee is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Audit Committee Financial Expert
Information concerning the Audit Committee Financial Expert is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners
Information concerning the ownership of certain beneficial owners is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Security of Ownership of Management
Information on security ownership of directors and officers is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
Equity Compensation Plan Information
Information concerning our equity compensation plans is included in Part II, Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities of this Annual Report on Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information on certain relationships and related transactions and director independence is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information concerning the principal accountant’s fees and services is set forth in our 2007 definitive Proxy Statement and is incorporated herein by this reference.
PART IV.
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Documents Filed as Part of this Report
(1) Exhibits
(3) Financial Statement Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ONEOK, Inc.
Registrant
Date: February 28, 2007
By:
/s/ Curtis L. Dinan
Curtis L. Dinan
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 28th day of February 2007.
/s/ John W. Gibson
/s/ David L. Kyle
John W. Gibson
David L. Kyle
Chief Executive Officer
Chairman of the Board of Directors
/s/ Caron A. Lawhorn
/s/ William M. Bell
Caron A. Lawhorn
William M. Bell
Senior Vice President and Chief Accounting Officer
Director
/s/ James C. Day
/s/ William L. Ford
James C. Day
William L. Ford
Director
Director
/s/ Bert H. Mackie
/s/ Pattye L. Moore
Bert H. Mackie
Pattye L. Moore
Director
Director
/s/ Gary D. Parker
/s/ Eduardo A. Rodriguez
Gary D. Parker
Eduardo A. Rodriguez
Director
Director
/s/ David J. Tippeconnic
/s/ Mollie B. Williford
David J. Tippeconnic
Mollie B. Williford
Director
Director