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 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 natural gas liquids systems that connect much of the natural gas and NGL supply in the Mid-Continent and Gulf Coast regions with key market centers in Conway, Kansas, Mont Belvieu, Texas, and Chicago, Illinois.
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 the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of sales to unaffiliated customers, operating income and total assets by business segment.
SIGNIFICANT DEVELOPMENTS IN 2007 AND EARLY 2008
In February 2008, ONEOK Partners announced plans to construct a 78-mile natural gas liquids gathering pipeline to connect two natural gas processing plants in the Woodford Shale area in southeast Oklahoma at a cost of approximately $25 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. These two plants are expected to produce approximately 25 MBbl/d of unfractionated NGLs. Until the Arbuckle Pipeline project is completed, the natural gas liquids production will be transported by ONEOK Partners’ existing Mid-Continent natural gas liquids pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported to ONEOK Partners’ Mont Belvieu, Texas, fractionation facility.
In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan Energy Partners, L.P. (Kinder Morgan) for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland.
In September 2007, ONEOK Partners completed an underwritten public debt offering of $600 million to finance the assets acquired from Kinder Morgan and to repay outstanding debt under its revolving credit facility agreement (ONEOK Partners Credit Agreement), which was incurred to fund ONEOK Partners’ internal growth capital projects.
During 2007, ONEOK Partners began construction on the Overland Pass Pipeline Company joint-venture project with a subsidiary of The Williams Companies, Inc. (Williams). Overland Pass Pipeline Company is building a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs, which can be increased to approximately 150 MBbl/d with additional pump facilities. This project has received the required approvals of various state
and federal regulatory authorities, and ONEOK Partners is constructing the pipeline with start-up currently scheduled for the second quarter 2008.
In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be transported by the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required state and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the second quarter of 2009.
In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquids and will connect ONEOK Partners’ existing Mid-Continent infrastructure and its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. Construction of the pipeline will require permits from various federal, state and local regulatory bodies. Construction is currently expected to begin in mid-2008 and be completed by early 2009.
In March 2007, ONEOK Partners announced the expansion of its Grasslands natural gas processing facility in North Dakota. The Grasslands facility is ONEOK Partners’ largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The expansion project is expected to come on-line in phases, with the final phase currently expected to be on-line in the third quarter of 2008.
In January 2007, Fort Union Gas Gathering announced that it will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. ONEOK Partners owns approximately 37 percent of Fort Union Gas Gathering. The expansion will occur in two phases. Phase 1 was placed in service during the fourth quarter of 2007. Phase 2 is currently expected to be in service during the second quarter of 2008.
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, together, 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 R of the 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 focuses on safe, environmentally sound and compliant operations for its employees, contractors, customers and the public.
ONEOK Partners’ focus is on expanding and acquiring assets in the United States related to energy transportation, gathering, processing, fractionation, storage and marketing natural gas and NGLs that will utilize its core competencies, minimize commodity price risk and provide long-term, sustainable and stable 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. 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 for all periods presented. 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 raw 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 raw natural gas production from 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, unfractionated NGL stream. This stream is then 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 residue 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 residue gas containing the same amount of Btus as the raw natural gas that was originally delivered.
ONEOK Partners also gathers, treats, fractionates, transports and stores NGLs. Its natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas and Texas to its fractionation facilities in Medford, Oklahoma, Hutchinson and Conway, Kansas, and Mont Belvieu, Texas. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, refineries and propane distributors through ONEOK Partners’ distribution pipelines that move NGL products from Oklahoma and Kansas to the market centers in Conway, Kansas, Mont Belvieu, Texas as well as the Midwest markets near Chicago, Illinois.
Operating revenue for the natural gas liquids gathering and fractionation business is primarily derived from the following types of services:
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Exchange services - ONEOK Partners gathers and transports unfractionated 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.
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Storage services - ONEOK Partners stores NGLs.
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Transportation - ONEOK Partners transports NGLs under its FERC-regulated tariffs.
ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines. ONEOK Partners’ pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission, OkTex Pipeline Company L.L.C. and a 50 percent interest in Northern Border Pipeline.
ONEOK Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. ONEOK Partners also has access to the major natural gas producing area in south central Kansas. In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, and transport natural gas 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 owns or reserves storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.
ONEOK Partners’ revenues from its natural gas pipelines are typically derived from fee services under the following types of contracts:
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Firm service - Customers can reserve a fixed quantity of pipeline or storage capacity for the term of their contract. Under this type of contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage, and is generally guaranteed access to the capacity they reserve.
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Interruptible service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm service requests are satisfied or on an as available basis. Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available.
Operating income from our ONEOK Partners segment was 54 percent, 53 percent and 49 percent of our consolidated operating income from continuing operations excluding the gain on sale of assets in 2007, 2006 and 2005, 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 11 percent, 13 percent and 19 percent of our ONEOK Partners segment’s revenues in 2007, 2006 and 2005, respectively.
Market Conditions and Seasonality - ONEOK Partners’ business is affected by the economy, commodity 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 storage activity for natural gas and natural gas liquids. In addition, its intrastate natural gas pipelines and natural gas liquids pipelines and fractionation facilities are affected by operational or market-driven changes in the output of the gas processing plants to which they are connected. Natural gas and NGL output from gas processing plants may increase or decrease affecting the volume of natural gas and NGLs transported through the systems as a result of the gross processing spread, which is the difference between the relative value of the composite price of NGLs to the price of natural gas, primarily ethane 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 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, current and forward 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 2007, both crude oil and natural gas prices were volatile, with NYMEX crude oil settlement prices ranging from $51.13 to $95.10 per Bbl and NYMEX natural gas settlement prices ranging from $5.43 to $7.59 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 United States 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 United States 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.
The factors that typically affect ONEOK Partners’ ability to compete for obtaining natural gas supplies for gathering and processing operations 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 and fractionation 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 gross processing 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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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 its 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 the transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. 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, its natural gas processing plants are exempt from FERC jurisdiction. The Natural Gas Act 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 for 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.
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.
ONEOK Partners’ interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of the pipeline activities. 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.
ONEOK Partners’ proprietary natural gas liquids gathering pipelines in both Oklahoma and Kansas are not regulated by the FERC or the states’ respective corporation commissions. ONEOK Partners’ remaining natural gas liquids gathering and distribution pipelines are interstate pipelines regulated by the FERC and by the United States Department of Transportation’s Office of Pipeline Safety (OPS). ONEOK Partners transports unfractionated NGLs and purity NGL products pursuant to filed tariffs.
Distribution
Business Strategy - Our Distribution segment focuses on safe, environmentally sound and compliant operations for its employees, contractors, customers and the public. Our integrated strategy for our LDCs incorporates a rates and regulatory plan that includes positive relationships with regulators, consistent strategies and synchronized rate case filings. We focus on growth of our rate and customer base through prudent investment in our system while emphasizing cost control. We provide customer choice programs that 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, such as cities, governmental agencies and schools.
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 our Distribution segment was 21 percent, 16 percent and 21 percent of our consolidated operating income from continuing operations excluding the gain on sale of assets in 2007, 2006 and 2005, respectively. Our Distribution segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for less than one percent of our Distribution segment’s revenues in 2007 and 2006, and there were none in 2005.
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 87 percent, 70 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 79 and 20 percent of natural gas sales, respectively, in Oklahoma; 71 and 19 percent of natural gas sales, respectively, in Kansas; and 68 and 24 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 impact margins. 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. Reduced rate transportation service may be negotiated when a competitive pipeline is in proximity or another energy option is available. Increased competition could potentially lower these rates. Industrial sales and transportation service tend to remain relatively constant throughout the year. Texas Gas Service files all negotiated transportation service contracts under a separate, confidential tariff at the RRC.
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. Oklahoma Natural Gas was recently authorized by the OCC to implement a natural gas hedge program as a three-year pilot program, with up to $10 million per year in hedge costs to be recovered from 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 96 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 43 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 previously 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 Natural Gas Policy Act and other intrastate transportation revenues.
Energy Services
Business Strategy - Our Energy Services segment creates 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 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. At December 31, 2007, our total storage capacity under lease was 96 Bcf, with maximum withdrawal capability of 2.4 Bcf/d and maximum injection capability of 1.6 Bcf/d. At December 31, 2007, our transportation capacity was 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 of value to our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize these positions through our application of market knowledge and risk management skills.
We actively manage the commodity price and volatility risks 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.
Numerous risk management opportunities and operational strategies exist that can be implemented through the use of storage facilities and transportation capacity. We utilize our industry knowledge and expertise in order to capitalize on opportunities that are provided through market volatility. We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and to generate additional returns. We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship.
Our working capital requirements related to our inventory in storage were as high as $581.1 million during 2007, but had decreased to $429.5 million at December 31, 2007. In addition, margin requirements can result in increased working capital requirements. During 2007, our margin requirements with counterparties ranged from zero to $144.8 million.
Operating income from our Energy Services segment was 25 percent, 31 percent and 31 percent of our consolidated operating income from continuing operations excluding the gain on sale of assets in 2007, 2006 and 2005, respectively. Our Energy Services segment had no single external customer from which it received 10 percent or more of consolidated revenues in 2007, 2006 or 2005. Intersegment sales accounted for 7 percent of our total revenues in 2007, compared with 8 percent in both 2006 and 2005.
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 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. 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.
Other
Segment Description - The primary companies in our Other segment include ONEOK Leasing Company 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 our Other segment.
Through ONEOK Leasing Company 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 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.
In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term, which is set to expire on September 30, 2009. In addition, ONEOK Leasing Company has entered into a purchase agreement with the owner of ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building to a date on or before March 31, 2008, for the total purchase price of approximately $48 million.
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 2005. Effective January 1, 2006, we were required to consolidate ONEOK Partners. See “Significant Accounting Policies” in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Our Other segment had no single external customer from which it received 10 percent or more of consolidated revenues.
ENVIRONMENTAL AND SAFETY MATTERS
Information about our environmental matters is included in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Pipeline Safety - We are subject to United States Department of Transportation integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on segments of a pipeline that pass through densely populated areas or near specifically identified sites that are designated as high consequence areas. To our knowledge, we are substantially in compliance with all material requirements associated with the various regulations.
Air and Water Emissions - The federal Clean Air Act and Clean Water Act and analogous state laws impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federal operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants discharged in United States water.
Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.
Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. After receiving these reports, Homeland Security will identify which sites are required to implement minimum security measures. Homeland Security is in the initial stages of implementing this rule, and the extent to which the rule will require us to undertake additional expenditures for site security is uncertain at this point.
Climate Change - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) maintaining an accurate greenhouse gas emissions inventory, (ii) improving the efficiency of our various pipeline and gas processing facilities, (iii) following developing technologies for emission control, (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere, and (v) analyzing options for future energy investment.
Currently, operating entities within ONEOK Partners participate in the gathering and processing and the transmission sectors of the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. Although they already utilize many of the identified “best practices,” it is anticipated that our LDCs will soon formally join the STAR Program’s distribution sector. In addition, we continue to focus on reducing methane loss through expanded implementation of best practices across our operations and analyzing options for additional emission reductions, including (i) closing older facilities and routing products to more efficient facilities, (ii) self-imposing permit limits at facilities where operationally feasible, (iii) utilizing electric motors on select compressor applications, and (iv) utilizing methods to limit the release of methane gas during pipeline maintenance and operations.
EMPLOYEES
We employed 4,555 people at January 31, 2008, including 730 people employed by Kansas Gas Service who were subject to collective bargaining contracts. 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, 2008.
Union
Employees
Contract Expires
United Steelworkers of America
June 30, 2009
International Union of Operating Engineers
June 30, 2009
International Brotherhood of Electrical Workers
June 30, 2010
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.
Name and Position
Age
Business Experience in Past Five Years
David L. Kyle
2007 to present
Chairman of the Board of Directors
Chairman of the Board of Directors
2000 to 2006
Chairman of the Board of Directors, President and Chief Executive Officer
1995 to present
Member of the Board of Directors
John W. Gibson
2007 to present
Chief Executive Officer
Chief Executive Officer
2006 to present
Member of the Board of Directors
and Member of the Board of Directors
President and Chief Operating Officer of ONEOK Partners, L.P.
2005 to 2006
President, ONEOK Energy Companies
2000 to 2005
President, Energy
Jim Kneale
2007 to present
President and Chief Operating Officer
President and Chief Operating Officer
2004 to 2006
Executive Vice President - Finance and Administration and Chief Financial Officer
2001 to 2004
Senior Vice President, Treasurer and Chief Financial Officer
Curtis L. Dinan
2007 to present
Senior Vice President, Chief Financial Officer and Treasurer
Senior Vice President,
2004 to 2006
Senior Vice President and Chief Accounting Officer
Chief Financial Officer and Treasurer
Vice President and Chief Accounting Officer
2002 to 2004
Assurance and Business Advisory Partner, Grant Thornton, LLP
John R. Barker
2004 to present
Senior Vice President and General Counsel
Senior Vice President and
1994 to 2004
Stockholder, President and Director, Gable & Gotwals
General Counsel
Caron A. Lawhorn
2007 to present
Senior Vice President and Chief Accounting Officer
Senior Vice President and
2005 to 2006
Senior Vice President, Financial Services and Treasurer
Chief Accounting Officer
2004 to 2005
Vice President and Controller
2003 to 2004
Vice President of Audit and Risk Control
1998 to 2003
Manager of Audit Services
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, www.oneok.com, 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, our investors need to 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,” which are 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.
Our partnership interest in ONEOK Partners is one of our largest cash-generating assets. 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 2007 Annual Report on Form 10-K.
Some of our nonregulated businesses have a higher level of risk than our regulated businesses.
Some of our nonregulated operations, which include ONEOK Partners’ gathering and processing, natural gas liquids gathering and fractionation, and our marketing and trading businesses, have a higher level of risk than our regulated operations, which include our utility and ONEOK Partners’ natural gas and natural gas liquids transportation businesses. We expect to continue investing in natural gas and natural gas liquids 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 LDCs have recorded certain assets that may not be recoverable from their customers.
Accounting policies for our LDCs 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 LDCs, 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 and natural gas liquids industries are 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 plants.
We cannot predict when we will be subject to 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: (i) the extent to which acquisitions and investment opportunities become available; (ii) our success in bidding for the opportunities that do become available; (iii) regulatory approval, if required, of the acquisitions on favorable terms; and (iv) 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 long-term senior unsecured debt has been assigned an investment grade 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 Energy Services segment. 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 margin thresholds are met. The additional increase in capital required to support our Energy Services segment 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.
Our business is subject to increased regulatory oversight and potential penalties.
The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not be pursued by the FERC and U.S. Congress, especially in light of previous market power abuse by certain companies engaged in interstate commerce. In response to this issue, U.S. Congress, in the Energy Policy Act of 2005 (EPACT), developed requirements intended to ensure that the energy market is not impacted by the exercise of market power or manipulative conduct. The FERC then adopted the Market Manipulation Rules to implement the authority granted under EPACT. These rules are intended to prohibit fraud and manipulation and are subject to broad interpretation. EPACT also gave the FERC increased penalty authority for violations.
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 Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) our ability to maintain our investment-grade credit ratings; and (vi) 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, 2008, 748 of our 4,555 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.
Certain of our nonregulated businesses are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs and crude oil. 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’ processing contracts and the difference between natural gas and NGLs, as well as the individual NGL products, prices with respect to natural gas and NGL transportation, fractionation and exchange agreements and natural gas and NGLs in storage utilized in our operations. 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 customers from upward volatility in the market price of natural gas. Oklahoma Natural Gas was recently authorized by the OCC to implement a natural gas hedge program as a three-year pilot program, with up to $10 million per year in hedge costs to be recovered from customers. 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 and its unitholders.
RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS
The volatility of natural gas, crude oil and NGL prices could adversely affect ONEOK Partners’ cash flow.
A significant portion of ONEOK Partners’ revenues are derived from the sale of commodities received as payment for its natural gas gathering and processing services, for transportation and storage of natural gas and NGLs, and for the fractionation of NGLs. As a result, ONEOK Partners is sensitive to commodity price fluctuations. Commodity prices have been and are likely to continue to be volatile in the future. High commodity prices and large commodity price spreads may not continue and could drop precipitously in a short period of time. The prices of commodities are subject to wide fluctuations in response to a variety of factors beyond ONEOK Partners’ control, including the following:
•
relatively minor changes in the supply of, and demand for, domestic and foreign energy,
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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, crude oil, NGL and liquefied natural gas 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 commodities and the impact commodity price fluctuations have on our customers and their need for our services. As commodity 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 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, and crude oil prices. Market risk refers to the risk of loss arising from adverse changes in commodity energy prices. ONEOK Partners’ primary exposure arises from commodity prices with respect to processing agreements, the difference between NGL and natural gas prices with respect to our natural gas and NGL transportation, fractionation and exchange agreements, and the differential between the individual NGL 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.
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.
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 new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to ONEOK Partners’ existing pipelines and existing gathering, processing, storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and fractionation facilities requires the expenditure of significant amounts of capital, which may exceed ONEOK Partners’ estimates, 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 ONEOK Partners’ 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.
ONEOK Partners’ inability to execute growth and development projects and acquire new assets could reduce cash distributions to its 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, its future growth will be limited, which could adversely impact the results of operations.
ONEOK Partners’ operations are subject to operational hazards and unforeseen interruptions, which could adversely affect its business and for which ONEOK Partners may not be adequately insured.
ONEOK Partners’ operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering and transportation pipelines, storage facilities and processing and fractionation plants. Operating risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes, and the performance of pipeline facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, the collision of equipment with ONEOK Partners’ pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near ONEOK Partners’ facilities), and catastrophic events such as explosions, fires, earthquakes, floods or other similar events beyond ONEOK Partners’ control. It is also possible that ONEOK Partners’ infrastructure facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred, and interruptions to the operation of ONEOK Partners’ pipeline caused by such an event, could reduce revenues generated by ONEOK Partners and increase expenses, thereby impairing ONEOK Partners’ ability to meet its obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.
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.
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’ interstate gas transportation services could significantly decrease.
ONEOK Partners depends on natural gas supply from the Western Canada Sedimentary Basin because ONEOK Partners’ interstate pipelines primarily transport 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’ interstate 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.
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.
ONEOK Partners’ regulated natural gas pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.
ONEOK Partners’ regulated natural gas pipelines are subject to extensive regulation by the FERC and state regulatory agencies, which regulate 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.
ONEOK Partners’ regulated pipeline companies 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.
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’ business. 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 an inherent risk of incurring 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. Additional information is included under Item 1, Business under “Environmental and Safety Matters” and in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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.
In the competition for customers, ONEOK Partners may have significant levels of uncontracted or discounted transportation capacity on its natural gas and natural gas liquids pipelines.
ONEOK Partners’ natural gas and natural gas liquids pipeline businesses compete with other pipelines for natural gas and natural gas liquids 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 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 producers, NGL end users 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 assesses the credit worthiness of its customers and obtains security as it deems appropriate. 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 file for bankruptcy protection, ONEOK Partners’ results of operations may be negatively impacted.
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 long-term debt has been assigned an investment grade rating by Moody’s of “Baa2” (Stable) and by S&P 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 or S&P were to downgrade ONEOK Partners’ long-term debt 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.
A downgrade of ONEOK Partners’ credit rating may require ONEOK Partners to offer to repurchase certain of its senior notes or may impair its ability to access capital.
ONEOK Partners could be required to offer to repurchase certain of its senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s or S&P rates those senior notes below investment grade (Baa3 for Moody’s and BBB- for S&P). Further, the indenture governing ONEOK Partners’ senior notes due 2010 and 2011 includes an event of default upon acceleration of other indebtedness of $25 million or more and the indenture governing ONEOK Partners’ senior notes due 2012, 2016, 2036 and 2037 includes 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, 2036 and 2037 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 ONEOK Partners to borrow money under its credit facilities or seek alternative financing sources to finance the repayments and repurchases. 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.
ONEOK Partners has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of its limited partner units.
When ONEOK Partners issues additional units or engages in certain other transactions, ONEOK Partners determines the fair market value of its assets and allocates any unrealized gain or loss attributable to its assets to the capital accounts of its unitholders and its general partner. ONEOK Partners’ methodology may be viewed as understating the value of its assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under ONEOK Partners’ current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated
to ONEOK Partners’ tangible assets and a lesser portion allocated to ONEOK Partners’ intangible assets. The IRS may challenge ONEOK Partners’ valuation methods, or ONEOK Partners’ allocation of the Section 743(b) adjustment attributable to ONEOK Partners’ tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of ONEOK Partners’ unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to ONEOK Partners’ unitholders. It also could affect the amount of gain from ONEOK Partners unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to ONEOK Partners unitholders’ tax returns without the benefit of additional deductions.
ONEOK Partners’ treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.
Because ONEOK Partners cannot match transferors and transferees of common units, ONEOK Partners is required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. ONEOK Partners does so by adopting certain depreciation conventions that do not conform to all aspects of the United States Treasury regulations. An IRS challenge to these conventions could adversely affect the tax benefits to a unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to ONEOK Partners unitholders’ tax returns.
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:
•
approximately 14,300 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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thirteen active gas processing plants with approximately 725 MMcf/d of owned, leased or contracted processing capacity in the Mid-Continent and Rocky Mountain regions,
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approximately 18 MBbl/d of natural gas liquids fractionation capacity in the Mid-Continent and Rocky Mountain regions,
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approximately 1,290 miles of FERC-regulated interstate natural gas pipelines with approximately 2.4 Bcf/d of peak transportation capacity,
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approximately 5,630 miles of intrastate natural gas gathering and state-regulated intrastate transmission pipelines with peak transportation capacity of approximately 2.9 Bcf/d,
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five underground natural gas storage facilities in Oklahoma, three underground natural gas storage facilities in Kansas and three underground natural gas storage facilities in Texas with total active working gas capacity of approximately 51.6 Bcf,
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50 percent interest in Northern Border Pipeline,
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approximately 2,570 miles of owned and contracted natural gas liquids gathering pipelines with peak capacity of approximately 270 MBbl/d,
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approximately 3,513 miles of primarily FERC-regulated natural gas liquids distribution pipelines with peak capacity of 496 MBbl/d,
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interest in four natural gas liquids fractionators with proportional operating capacity of approximately 399 MBbl/d,
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one 9 MBbls/d isomerization unit,
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NGL storage facilities with operating storage capacity of approximately 25.6 MMBbl,
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approximately 720 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 93 MBbl/d, and
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eight NGL product terminals in Missouri, Nebraska, Iowa and Illinois.
Distribution
We own approximately 18,100 miles of pipeline and other distribution facilities in Oklahoma, approximately 13,300 miles of pipeline and other distribution facilities in Kansas and approximately 9,500 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 96 Bcf, with maximum withdrawal capability of 2.4 Bcf/d and maximum injection capability of 1.6 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 23 different facilities in seven states and two facilities 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 the seventeen-story ONEOK Plaza office building with approximately 517,000 square feet of net rentable space. We currently lease ONEOK Plaza 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. In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term, which is set to expire on September 30, 2009. In addition, ONEOK Leasing Company has entered into a purchase agreement with the owner of ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building to a date on or before March 31, 2008, for the total purchase price of approximately $48 million.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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.
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 was 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 court awarded $2,047,406 in fees and $646,090.78 in expenses, which was also covered by insurance. 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 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. On October 26, 2007, the Kansas Supreme Court issued unanimous opinions on the appeals of the class action verdicts. The Court (i) affirmed the no damage verdict in favor of defendants in the Gilley business class, and (ii) reversed the $5 million actual damage verdict and $2.6 million attorneys fees and costs awarded to the Smith residential class, with instructions to enter judgment in favor of defendants. Plaintiffs’ rights to file a motion for a rehearing expired without plaintiffs taking any action, and the Court’s judgment was entered as directed on December 20, 2007. This case and all other cases regarding the gas explosions have been fully resolved.
Gas Index Pricing Litigation: We, ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together, 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); Arandell Corporation, et al. v. Xcel Energy, Inc., et al. (filed in the Circuit Court for Dane County, Wisconsin, in December 2006,transferred to MDL-1566 in the United States District Court for the District of Nevada); Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al. (filed in the Circuit Court of Buchanan County, Missouri, transferred to MDL-1566 in the United States District Court for the District of Nevada). 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 arise out of 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 or motions for summary judgment.
Motions to dismiss were granted in the Leggett and Sinclair cases. The dismissal of the Sinclair case was appealed to the United States Court of Appeals for the Ninth Circuit. Because of recent decisions by the Ninth Circuit in similar cases, OESC has advised the Ninth Circuit that it has elected to withdraw its opposition to the appeal and consents to a remand of the case back to MDL-1566 in the United States District Court for the District of Nevada for further proceedings. The dismissal of the Leggett case was appealed by the plaintiffs to the Tennessee Court of Appeals which has been fully briefed and awaits a ruling by the court. On February 18, 2008, summary judgment was granted in favor of us and OESC in the Breckenridge case. 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 2007.
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.
At February 20, 2008, there were 14,457 holders of record of our 104,060,539 outstanding shares of common stock.
DIVIDENDS
The following table sets forth the quarterly dividends paid per share of our common stock during the periods indicated.
A quarterly dividend of $0.38 per share was declared in January 2008, payable in the first quarter of 2008.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2007.
(1) Includes shares granted under our Employee Stock Purchase Plan, and 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 these plans, see Note O of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 625,901, 1,170,987, 1,114,410 shares available for future issuance under our Employee Stock Purchase Plan, Long-Term Incentive Plan and Equity Compensation 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 O of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 464,557, 2,165,938, 972,101 and 55,648 shares available for future issuance under our Stock Compensation Plan for Non-Employee Directors, Thrift Plan, Profit Sharing Plan and Employee Stock Award Program, respectively. The Employee Stock Award Program is 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 $44.77, which represents the year-end closing price of our common stock.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of our common stock for the periods shown.
(1) Represents shares repurchased directly from employees, pursuant to our Employee Stock Award Program.
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, 2007, a total of 144,352 shares had been issued to employees under this program. The shares issued under this program have not been registered under the Securities Act of 1933, as amended (1933 Act), in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not require registration under the 1933 Act.
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, 2002, and ending on December 31, 2007. 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, 2002, and at the End of Every Year Through December 31, 2007
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 Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Dynegy, Inc.; Edison International; Entergy Corp.; Exelon Corp.; FirstEnergy Corp.; FPL Group, Inc.; Integrys Energy Group, Inc.; Nicor, Inc.; NiSource, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Questar Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; 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.
See discussion of acquisitions, dispositions and changes in consolidation beginning on page 29 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 Consolidated Financial Statements for a complete explanation of the following items.
Diluted earnings per share of common stock from continuing operations (EPS) increased to $2.79 in 2007, compared with $2.68 in 2006. The increase in operating income for 2007, compared with 2006, and exclusive of the gain on sale of assets, is primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment and new supply connections and higher product price spreads in our ONEOK Partners’ natural gas liquids businesses. This increase was partially offset by reduced operating income in our Energy Services segment primarily due to decreased transportation margins during 2007.
In September 2007, ONEOK Partners completed an underwritten public debt offering of $600 million to finance the assets acquired from Kinder Morgan and to repay outstanding debt under the ONEOK Partners Credit Agreement, which was incurred to fund ONEOK Partners’ internal growth capital projects. The assets acquired from Kinder Morgan and ONEOK Partners’ capital projects are discussed below in the Significant Acquisitions and Divestitures and the Capital Projects sections, respectively.
We declared a quarterly dividend of $0.38 per share ($1.52 per share on an annualized basis) in January 2008, an increase of approximately 12 percent over the $0.34 declared in January 2007. ONEOK Partners declared an increase in its cash distribution to $1.025 per unit ($4.10 per unit on an annualized basis) in January 2008, an increase of approximately 5 percent over the $0.98 declared in January 2007.
SIGNIFICANT ACQUISITIONS AND DIVESTITURES
In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of three refined petroleum products terminals
and connecting pipelines. Financing for this transaction came from the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion on the 2037 Notes.
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 a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control of the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, is 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 Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K beginning on page 68 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, and an affiliate of TransCanada became operator of the pipeline in April 2007. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method applied on a retroactive basis to January 1, 2006.
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 accounted for on a retroactive basis 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 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. See “Discontinued Operations” on page 46 for additional information.
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 MBbl/d 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 Venice Energy Services Company, L.LC. These assets are included in our consolidated financial statements beginning on July 1, 2005, and were part of the assets ONEOK Partners acquired from us in April 2006.
CAPITAL PROJECTS
All of the capital projects discussed below are in our ONEOK Partners segment.
Woodford Shale Natural Gas Liquids Pipeline Extension - In February 2008, ONEOK Partners announced plans to construct a 78-mile natural gas liquids gathering pipeline to connect two natural gas processing plants in the Woodford Shale area in southeast Oklahoma at a cost of approximately $25 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. These two plants are expected to produce approximately 25 MBbl/d of unfractionated NGLs. Until the Arbuckle Pipeline project is completed, the natural gas liquids production will be transported by ONEOK Partners’ existing Mid-Continent natural gas liquids pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported to ONEOK Partners’ Mont Belvieu, Texas, fractionation facility.
Overland Pass Pipeline Company - 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. Overland Pass Pipeline Company is building a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs, which can be increased to approximately 150 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have 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. This project has received the required approvals of various state and federal regulatory authorities, and ONEOK Partners is constructing the pipeline with start-up currently scheduled for the second quarter of 2008.
As part of a long-term agreement, Williams dedicated its NGL production from two of its natural 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 currently estimated to cost approximately $535 million, excluding AFUDC. Since ONEOK Partners’ initial estimate in early 2006, there has been a significant increase in the demand for pipeline construction-related services, which has led to higher rates, particularly for construction labor and equipment. Additionally, due to the extended permitting process, ONEOK Partners is constructing the pipeline during the winter months, which could contribute to added construction costs and could cause further delays. The severity of the winter conditions could further impact ONEOK Partners’ cost and schedule estimates. In addition, ONEOK Partners is investing approximately $216 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.
Piceance Lateral Pipeline - In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be transported by the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required state and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the second quarter of 2009, at a current cost estimate of approximately $120 million, excluding AFUDC.
Arbuckle Pipeline Natural Gas Liquids Pipeline - In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast, at a current estimated cost of approximately $260 million, excluding AFUDC. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquids and will connect with ONEOK Partners’ existing Mid-Continent infrastructure and its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. Construction of the pipeline will require permits from various federal, state and local regulatory bodies. Construction is currently expected to begin in mid-2008 and be completed by early 2009.
Williston Basin Gas Processing Plant Expansion - In March 2007, ONEOK Partners announced the expansion of its Grasslands natural gas processing facility in North Dakota at a cost of approximately $30 million, excluding AFUDC. The Grasslands facility is ONEOK Partners’ largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The expansion project is expected to come on-line in phases, with the final phase currently expected to be on-line in the third quarter of 2008.
Fort Union Gas Gathering Expansion - In January 2007, Fort Union Gas Gathering announced that it will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. The expansion is expected to cost approximately $110 million, excluding AFUDC, which will be financed within the Fort Union Gas Gathering partnership and will occur in two phases. Phase 1, with more than 200 MMcf/d capacity, was placed in service during the fourth quarter of 2007. Phase 2, with approximately 450 MMcf/d capacity, is currently expected to be in service during the second quarter of 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. ONEOK Partners owns approximately 37 percent of Fort Union Gas Gathering, and accounts for its ownership under the equity method of accounting.
Guardian Pipeline Expansion and Extension - In December 2007, Guardian Pipeline received and accepted the certificate of public convenience and necessity issued by the FERC for its expansion and extension project. The certificate authorizes ONEOK Partners to construct, install and operate approximately 119 miles of a 20-inch and 30-inch natural gas transportation pipeline with a capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin to the Green Bay, Wisconsin, area. The project is supported by long-term shipper commitments. The cost of the project is currently estimated to be $260 million, excluding AFUDC. The pipeline is currently expected to be in service in the fourth quarter of 2008.
Midwestern Gas Transmission Eastern Extension - Midwestern Gas Transmission’s eastern extension pipeline was placed into service in January 2008. The extension added approximately 31 miles of natural gas transportation pipeline, with a capacity to transport 120 MMcf/d of natural gas from Midwestern’s previous terminus at Portland, Tennessee, to interconnects with Columbia Gulf Transmission Company and East Tennessee Natural Gas, LLC, near Hartsville, Tennessee. The project is supported by a long-term shipper commitment. Total capital expenditures are expected to be $62 million, excluding AFUDC.
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 43.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Statement 157, “Fair Value Measurements,” Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” 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,” Statement 123R, “Share-Based Payment,” Statement 141R, “Business Combinations” and Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” are included in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated 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 from our estimates.
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, Accounting for Financially Settled Transactions 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 a derivative instrument 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 57 for amounts in our portfolio at December 31, 2007, 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 nature of the risk being hedged and how we will determine if the hedging instrument is effective. 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, collars or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, condensate, and fuel requirements. 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 flow. 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 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.
Upon election, 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 are therefore exempt from fair value accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument is (i) held for trading purposes, (ii) financially settled, (iii) results in physical delivery or services rendered, and (iv) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows:
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all financially settled derivative contracts are reported on a net basis,
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derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis,
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derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis, and
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derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.
We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K 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.” There were no impairment charges resulting from the July 1, 2007, impairment tests and no events indicating an impairment have 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. At December 31, 2007, we had $600.7 million of goodwill recorded on our Consolidated Balance Sheet as shown below.
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 $443.0 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2007, of which $287.5 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. See “Discontinued Operations” on page 46 for additional information.
Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million as of December 31, 2007 and 2006. 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.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. 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 the 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 2007, we recorded net periodic benefit costs of $29.1 million related to our defined benefit pension plans and $26.7 million related to postretirement benefits. We estimate that in 2008, we will record net periodic benefit costs of $19.8 million related to our defined benefit pension plan and $28.3 million related to postretirement benefits. In determining our estimated expenses for 2008, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 6.25 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our 2008 estimated net periodic benefit costs by approximately $1.8 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 6.00 percent would increase our 2008 estimated net periodic benefit costs by approximately $2.5 million for our defined benefit pension plan and $0.7 million for our postretirement benefit plan. For 2008, we anticipate our total contributions to our defined benefit pension plan and postretirement benefit plan to be $3.1 million and $11.0 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $16.7 million.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal 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. See Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of contingencies.
FINANCIAL AND OPERATING RESULTS
Consolidated Operations
Selected Financial Information - The following table sets forth certain selected financial information for the periods indicated.
Operating Results - Net margin increased for 2007, compared with 2006, primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment. Net margin was also positively impacted during 2007 by our ONEOK Partners segment due to its natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold. Net margin also increased due to ONEOK Partners’
natural gas liquids gathering and fractionation business benefiting from higher product price spreads and higher isomerization price spreads as well as the incremental net margin related to the assets acquired from Kinder Morgan in October 2007. These increases were offset by decreased transportation margins in our Energy Services segment and decreased net margin in ONEOK Partners’ natural gas gathering and processing business, primarily due to lower natural gas volumes processed as a result of contract terminations in late 2006.
For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 43.
Consolidated operating costs increased for 2007, compared with 2006, primarily due to higher employee-related costs and the incremental operating expenses associated with ONEOK Partners’ acquisition of assets from Kinder Morgan in October 2007, coupled with increased bad debt expense and higher property taxes in our Distribution segment. These increases were partially offset by lower litigation costs in our ONEOK Partners segment and lower employee-related costs in our Distribution segment.
Depreciation and amortization decreased for 2007, compared with 2006, primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa Pipeline, which is included in our ONEOK Partners segment.
Gain (loss) on sale of assets decreased for 2007, compared with 2006, primarily due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment.
Equity earnings from investments decreased for 2007, compared with 2006, primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006.
Allowance for equity funds used during construction increased for 2007, compared with 2006, due to ONEOK Partners’ capital projects, which are discussed beginning on page 31.
Interest expense increased for 2007, primarily due to the additional borrowings by ONEOK Partners to complete the April 2006 transactions with us. The additional borrowings resulted in $21.3 million in higher interest expense in the first quarter of 2007 compared with the same period in 2006. Increased interest expense was partially offset by lower interest expense on short-term debt of $11.8 million during 2007, compared with the same period in 2006, as a result of the proceeds from the sale of assets to ONEOK Partners, which reduced short-term debt.
Minority interest in income of consolidated subsidiaries for 2007 and 2006 reflects the remaining 54.3 percent of ONEOK Partners that we do not own. For 2007, minority interest was lower due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment. Additionally, minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006.
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.
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 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. 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. For additional information, see discussion on page 30.
Equity earnings from investments increased $87.3 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.
Additional 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 2007, our basic and diluted earnings per share from continuing operations were $2.84 and $2.79, respectively, representing a 4 percent increase in basic earnings per share and a 4 percent increase in diluted earnings per share from continuing operations compared with 2006. 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. Return on invested capital was 14 percent in 2007 and 2006 compared with 23 percent in 2005. Our 2006 results include the impact from the gain on the sale of a 20 percent interest in Northern Border Pipeline. The significantly higher earnings per share results in 2005 are primarily related to the gain on the sale of our Texas gathering and processing assets; this gain on sale, coupled with the gain on the sale of our production assets, increased our return on invested capital in 2005.
To evaluate shareholder appreciation, we compare the total return of an investment in our stock with the total return of an investment in the stock of our peer companies. For the year ended December 31, 2007, we ranked third in this shareholder appreciation calculation when 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. 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 included in our ONEOK Partners segment for all periods presented. 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 Consolidated Statements 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 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, unfractionated NGL stream.
ONEOK Partners also gathers, treats, fractionates, transports and stores NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas and the Texas panhandle to fractionators it owns in Oklahoma, Kansas and Texas. ONEOK Partners’ NGL distribution assets connect the key NGL market centers in Conway, Kansas, and Mont Belvieu, Texas, as well as the Midwest markets near Chicago, Illinois.
ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines. ONEOK Partners’ intrastate natural gas pipeline assets access the major natural gas producing areas and transport natural gas throughout Oklahoma, Kansas and Texas. ONEOK Partners’ owns or reserves storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.
Acquisition and Divestitures - The following acquisition and divestitures are described beginning on page 75.
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In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland.
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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, and an affiliate of TransCanada became operator of the pipeline in April 2007.
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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.
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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.
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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 Venice Energy Services Company, L.L.C. Venice Energy Services Company, L.L.C. owns a gas processing complex near Venice, Louisiana.
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 data for the legacy ONEOK Partners operations beginning January 1, 2006. For additional information, see “Significant Accounting Policies” in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Net margin increased by $52.3 million in 2007, compared with 2006, primarily due to the following:
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increased performance of ONEOK Partners’ natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold,
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higher NGL product price spreads and higher isomerization price spreads in ONEOK Partners’ natural gas liquids gathering and fractionation business,
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the incremental net margin related to the acquisition of assets from Kinder Morgan in October 2007 in ONEOK Partners’ natural gas liquids pipelines business, and
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increased storage margins in ONEOK Partners’ natural gas pipelines business, that was partially offset by
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decreased natural gas processing and transportation margins in ONEOK Partners’ natural gas businesses resulting primarily from lower throughput, higher fuel costs and lower natural gas volumes processed as a result of various contract terminations.
Operating costs increased by $11.6 million during 2007, compared with 2006, primarily due to higher employee-related costs and the incremental operating expenses associated with the assets acquired from Kinder Morgan, partially offset by lower litigation costs.
Depreciation and amortization decreased by $8.3 million during 2007, compared with 2006, primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa Pipeline.
Gain on sale of assets decreased by $113.5 million during 2007, compared with 2006, primarily due to the $113.9 million gain on the sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006.
Equity earnings from investments for 2007 and 2006 primarily include earnings from ONEOK Partners’ interest in Northern Border Pipeline. The decrease of $6.0 million during 2007, compared with 2006, is primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 75 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.
Allowance for equity funds used during construction increased for 2007, compared with 2006, due to ONEOK Partners’ capital projects, which are discussed beginning on page 31.
Minority interest in income of consolidated subsidiaries decreased $2.0 million during 2007, compared with 2006, primarily due to our acquisition of the remaining interest in Guardian Pipeline. Minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006.
The increase of $508.1 million in capital expenditures during 2007, compared with 2006, is driven primarily by ONEOK Partners’ capital projects that are discussed beginning on page 31.
Net margin increased by $296.8 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 the operations of the assets ONEOK Partners acquired from us in April 2006, 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 $105.6 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 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. 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 the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
The increase in equity earnings from investments of $97.4 million for 2006, compared with 2005, 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.
For a discussion of market risk, see Item 7A, Quantitative and Qualitative Disclosures About Market Risk in this Annual Report on Form 10-K.
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 information for our Distribution segment for the periods indicated.
Operating Results - Net margin increased by $63.9 million during 2007, compared with 2006, primarily due to:
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an increase of $55.2 million resulting from the implementation of new rate schedules, which includes $51.1 million in Kansas and $4.1 million in Texas and
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an increase of $8.0 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory.
Operating costs increased $6.3 million during 2007, compared with 2006, primarily due to:
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an increase of $4.8 million in bad debt expense primarily in Oklahoma,
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an increase of $5.3 million due to higher property taxes in Kansas, and
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a decrease of $4.0 million in labor and employee benefit costs.
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, partially offset by
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a decrease of $7.6 million in bad debt expense.
Depreciation 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.
Selected Operating Data - The following tables set forth certain selected financial and operating information for our Distribution segment for the periods indicated.
Residential and commercial volumes increased during 2007, compared with 2006, primarily due to a return to more normal weather from the unseasonably warm weather in 2006.
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.
Wholesale sales represent contracted 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 during 2007, compared with 2006 and 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 $50.6 million, $54.9 million and $38.6 million for new business development in 2007, 2006 and 2005, respectively. Capital expenditures for new business development in 2007 was impacted by delayed housing starts due to wetter than normal weather and a decrease in housing permits in Oklahoma. 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 August 17, 2007, Oklahoma Natural Gas filed an application for authorization of a capital investment recovery mechanism as a means to more timely recover and earn a rate of return on the capital investments made for maintaining its distribution system. A joint stipulation was agreed to and signed by all parties in January 2008. This joint stipulation will allow Oklahoma Natural Gas to collect the carrying costs associated with non-revenue producing capital expenditures between rate filings. A general hearing on this matter was held on February 15, 2008. The rates are expected to generate approximately $7.6 million in revenues and are expected to be in place in March 2008.
Oklahoma Natural Gas was recently authorized by the OCC to implement a natural gas hedge program as a three-year pilot program, with up to $10 million per year in hedge costs to be recovered from customers.
In a 2005 rate filing, the parties stipulated that transmission pipeline Integrity Management Program (IMP) costs incurred in compliance with the Federal Pipeline Safety Improvement Act of 2002 should be addressed in a subsequent proceeding, and in an order issued in October of 2005, the OCC authorized Oklahoma Natural Gas to defer such costs (inclusive of operations and maintenance expense, depreciation, ad valorem taxes and a rate of return). On January 31, 2007, Oklahoma Natural Gas filed an application with the OCC seeking recovery of these costs. On August 31, 2007, the OCC issued an order approving a stipulation of the parties, which provides recovery of $7.2 million in IMP deferrals incurred as of July 31, 2007. The 2008 IMP application was made at the OCC on January 31, 2008, and covered the IMP deferrals for the months of August through December 2007, and the true-ups associated with the prior recovery period. This filing also requested $7.2 million to be recovered with a new IMP billing rate to be put in place in July 2008. Oklahoma Natural Gas will continue to defer IMP costs as they are incurred and will file a new application each year for recovery of any additional costs.
Kansas - In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other 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 is effective for services rendered on or after January 1, 2007.
Texas - In August 2007, Texas Gas Service filed for a rate adjustment with the city of El Paso and the municipalities of Anthony, Clint, Horizon City, Socorro and Vinton. Texas Gas Service requested a total increase of $5.5 million. On February 5, 2008, the El Paso City Council approved a rate increase of approximately $3.1 million. The increase is effective for meters read on or after February 15, 2008.
Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $1.7 million in annual rate increases were approved and implemented in the fourth quarter of 2007. A total of $5.5 million in annual rate increases were approved and implemented in 2006.
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 96 Bcf, with maximum withdrawal capability of 2.4 Bcf/d and maximum injection capability of 1.6 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. 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.
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.
Operating Results - Net margin decreased by $26.4 million during 2007, compared with 2006, primarily due to:
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a decrease of $22.0 million in transportation margins, net of hedging activities, associated with changes in the unrealized fair value of derivative instruments and the impact of a force majeure event on the Cheyenne Plains Gas Pipeline, as more fully described below,
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a decrease of $5.0 million in retail activities from lower physical margins due to market conditions and increased competition,
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a decrease of $4.3 million in financial trading margins, that was partially offset by
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an increase of $4.9 million in storage and marketing margins, net of hedging activities, related to:
o an increase in physical storage margins, net of hedging activity, due to higher realized seasonal storage spreads and optimization activities, partially offset by
o a decrease in marketing margins, and
o a net increase in the cost associated with managing our peaking and load following services, slightly offset by higher demand fees collected for these services.
In September 2007, a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company was curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment that was impacted by the force majeure event, resulted in a loss of approximately $5.5 million that was recognized in the third quarter. In addition, we incurred a margin loss of approximately $2.4 million in late 2007 on our actual physical transportation. We have filed a claim with our insurance carriers under our business interruption policy for reimbursement of losses incurred during the Cheyenne Plains pipeline capacity curtailments, which is currently being processed. Cheyenne Plains Gas Pipeline Company resumed full operations in November 2007.
Operating costs decreased $2.5 million in 2007, compared with 2006, primarily due to decreased legal and employee-related costs, and reduced ad-valorem tax expense.
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,
•
a net increase of $0.9 million related to storage and marketing margins primarily due to:
o 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,
o a decrease of $6.2 million related to power margins associated with a tolling transaction that expired December 31, 2005, and
•
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.
Natural gas volumes marketed increased during 2007, compared with 2006, due to an increase in sales activity in the southeastern United States in the third quarter of 2007. Natural gas volumes were also impacted by a 14 percent increase in heating degree days in our service territory, compared with the same period in 2006.
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.
Our natural gas in storage at December 31, 2007, was 66.7 Bcf, compared with 74.1 Bcf at December 31, 2006. At December 31, 2007, our total natural gas storage capacity under lease was 96 Bcf, compared with 86 Bcf at December 31, 2006.
The acquisition of natural gas storage capacity has become more competitive as a result of new entrants, increases 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 which are shown on page 52.
The following table shows the margins by activity for the periods indicated.
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.
Contingencies
Legal Proceedings - We are a party to various litigation matters and claims that 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.
Other - As a result of an internal review of a transaction that was brought to the attention of one of our affiliates by a third party, we have commenced an internal review of transactions that may have violated FERC capacity release rules or related rules. While our internal review is ongoing, we believe it is likely that a limited number of these transactions will have violated FERC capacity release rules or related rules. We have notified the FERC of this review and expect to file a report with the FERC by mid-March 2008 concerning any violations. At this time, we do not believe that penalties, if any, associated with potential violations will have a material impact on our results of operations, financial position or liquidity.
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.
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.
At the time of the sale, we retained a contract with the Oklahoma Municipal Power Authority (OMPA) that required us to provide OMPA with 75 megawatts of firm capacity per month for a monthly fixed charge of approximately $0.4 million through December 31, 2015. To fulfill our obligations under this contract, we entered into an agreement with Westar to purchase 75 megawatts of firm capacity on the same terms as our agreement with OMPA. In an arbitration ruling dated October 11, 2007, our contract with OMPA was terminated as of that date, and we were awarded payment for our services through that date. We are currently evaluating our alternatives with respect to our contract with Westar.
These components of our business are accounted for as discontinued operations. Accordingly, amounts in our consolidated 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 acquisitions and internally generated growth projects 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.
Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity and other recessionary concerns. During this period, ONEOK and ONEOK Partners have continued to have access to ONEOK’s commercial paper program and the ONEOK Partners Credit Agreement, respectively, to fund short-term liquidity needs. Additionally, ONEOK Partners issued $600 million of long-term debt in September 2007. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations will enable us to maintain our current level of operations and our planned operations including capital expenditures for the foreseeable future. We have no material guarantees of debt or other similar commitments to unaffiliated parties.
During 2007 and 2006, our capital expenditures were financed through operating cash flows and short- and long-term debt. Capital expenditures for 2007 were $883.7 million, compared with $376.3 million in 2006, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures during 2007 were $709.9 million, compared with $201.7 million for the same period in 2006, exclusive of acquisitions. The increase in capital expenditures for 2007, compared with 2006, is driven primarily by ONEOK Partners’ capital projects, which are discussed beginning on page 31.
Financing - For ONEOK, financing is provided through available cash, commercial paper and long-term debt. ONEOK also has a credit agreement, which is used as a back-up for its 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, asset securitization and sale/leaseback of facilities. ONEOK Partners’ operations are financed through available cash or the issuance of debt or limited partner units.
The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion. At December 31, 2007, ONEOK had $102.6 million of commercial paper outstanding, $58.7 million in letters of credit issued and available cash and cash equivalents of approximately $15.9 million. At December 31, 2007, ONEOK Partners had $900 million of credit available under the ONEOK Partners Credit Agreement, $100 million of borrowings outstanding under the ONEOK Partners Credit Agreement, as described in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, and available cash and cash equivalents of approximately $3.2 million. As of December 31, 2007, ONEOK could have issued $2.0 billion of additional debt under the most restrictive provisions contained in its various borrowing agreements. As of December 31, 2007, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, $1.1 billion of additional debt.
In November 2007, ONEOK Partners entered into a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is being used, and a $12 million Standby Letter of Credit Agreement with Royal Bank of Canada. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas.
In July 2007, ONEOK Partners exercised the accordion feature in the ONEOK Partners Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion.
ONEOK’s $1.2 billion credit agreement (ONEOK Credit Agreement) and the ONEOK Partners Credit Agreement contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. At December 31, 2007, ONEOK and ONEOK Partners were in compliance with all covenants.
ONEOK Partners Debt Issuance - In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC. The 2037 Notes are non-recourse to ONEOK. For more information regarding the 2037 Notes, refer to discussion in Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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, (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (collectively, 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 non-recourse to ONEOK. For more information regarding the Notes, refer to discussion in Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Capitalization Structure - The following table sets forth our consolidated capitalization structure for the periods indicated.
ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in ONEOK’s Credit Agreement, the debt of ONEOK Partners is excluded. At December 31, 2007, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 51 percent long-term debt and 49 percent equity, compared with 48 percent long-term debt and 52 percent equity at December 31, 2006. In February 2008, we repaid $402.3 million of maturing long-term debt with cash from operations.
Credit Ratings - Our investment grade credit ratings as of December 31, 2007, are shown in the table below.
ONEOK’s commercial paper is rated P2 by Moody’s and A2 by S&P. Credit ratings may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of 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 we are 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 credit agreement, which expires July 2011, and ONEOK Partners has access to a $1.0 billion revolving credit agreement that expires March 2012.
ONEOK Partners’ $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment grade rating is 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, 2036 and 2037 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, 2036 and 2037 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. A decline in ONEOK Partners’ credit rating below investment grade may also require ONEOK Partners to provide security to its counterparties in the form of cash, letters of credit or other negotiable instruments.
Our Energy Services segment relies upon the investment grade rating of ONEOK’s senior unsecured long-term debt to satisfy credit requirements with most of our counterparties. If ONEOK’s 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. At December 31, 2007, we could have been required to fund approximately $56.8 million in margin
requirements upon such a downgrade. A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.
Other than ONEOK Partners’ 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 rating triggers under ONEOK’s commercial paper agreement, trust indentures, building leases, equipment leases 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 and ONEOK Partners’ credit agreements contain provisions that would cause the cost to borrow funds to increase if their respective credit rating is negatively adjusted. An adverse rating change is not defined as a default of ONEOK’s or ONEOK Partners’ credit agreements.
Capital Projects - See the “Capital Projects” section beginning on page 31 for discussion of capital projects.
ONEOK Partners’ Class B Units - The units we received from ONEOK Partners were newly created Class B limited partner units. Distributions on the Class B limited partner units were prorated from the date of issuance. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners common units and generally have the same voting rights as the common units.
At a special meeting of the ONEOK Partners common unitholders held March 29, 2007, the unitholders approved a proposal to permit the conversion of all or a portion of the Class B limited partner units issued in the acquisition and consolidation of certain companies comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments in a series of transactions (collectively the ONEOK Transactions) into common units at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned to May 10, 2007, to allow unitholders additional time to vote on a proposal to approve amendments to the ONEOK Partners’ Partnership Agreement which, had the amendments been approved, would have granted voting rights for units held by us and our affiliates if a vote is held to remove us as the general partner and would have required fair market value compensation for our general partner interest if we are removed as general partner. While a majority of ONEOK Partners common unitholders voted in favor of the proposed amendments to the ONEOK Partners Partnership Agreement at the reconvened meeting of the common unitholders held May 10, 2007, the proposed amendments were not approved by the required two-thirds affirmative vote of the outstanding units, excluding the common units and Class B units held by us and our affiliates. As a result, effective April 7, 2007, the Class B limited partner units are entitled to receive increased quarterly distributions and distributions upon liquidation equal to 110 percent of the distributions paid with respect to the common units.
On June 21, 2007, we, as the sole holder of ONEOK Partners Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.
In addition, since the proposed amendments to the ONEOK Partners’ Partnership Agreement were not approved by the common unitholders, if the common unitholders vote at any time to remove us or our affiliates as the general partner, quarterly distributions payable on Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.
Stock Repurchase Plan - For more information regarding the Stock Repurchase Plan, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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, the cost of transportation to various market locations, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and ONEOK Partners’ lines of credit are adequate to meet liquidity requirements associated with commodity price volatility.
Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
ENVIRONMENTAL LIABILITIES
Information about our environmental liabilities is included in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
CASH FLOW ANALYSIS
Our Consolidated Statements of Cash Flows combine cash flows from discontinued operations with cash flows from continuing operations within each category. Discontinued operations accounted for approximately $77.2 million in operating cash inflows for the year ended December 31, 2005. Discontinued operations accounted for approximately $44.4 million in investing cash outflows for the year ended December 31, 2005, and did not account for any financing cash flows. The absence of cash flows from our discontinued operations did not have a significant impact on our future cash flows.
Operating Cash Flows - Operating cash flows increased by $156.4 million for 2007, compared with 2006. Working capital increased operating cash flows by $209.9 million for 2007, compared with an increase of $59.7 million for 2006.
Operating cash flows increased by $1.0 billion for 2006, compared with 2005, primarily as a result of changes in components of working capital which increased operating cash flows by $59.7 million for 2006, compared with a decrease of $580.8 million for 2005, 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, compared with 2005, was also impacted by the consolidation of ONEOK Partners as of January 1, 2006. 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.
Investing Cash Flows - Cash used in investing activities was $1.2 billion for 2007, compared with $237.2 million for 2006. The increased use of cash during 2007 was primarily related to an increase in capital expenditures of $507.4 million when compared with 2006. For further discussion of ONEOK Partners’ capital projects, see page 31.
In October 2007, ONEOK Partners acquired an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments.
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, in October 2006.
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 natural gas liquids pipeline joint venture.
Acquisitions in 2005 primarily represent the purchase of the natural gas liquids assets from Koch. 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 other investing activities.
We had a decrease in short-term investments of $31.1 million between December 31, 2006, and December 31, 2007, compared with a total investment of $31.1 million for 2006. During 2007, we had less cash to invest following our repurchase of 7.5 million shares of our outstanding common stock in June.
Investing cash flows for 2006 also include the impact of the deconsolidation of Northern Border Pipeline and consolidation of Guardian Pipeline.
Financing Cash Flows - Cash provided by financing activities was $73.0 million for 2007, compared with cash used in financing activities of $618.8 million for 2006, and cash provided by financing activities of $694.9 million in 2005.
In 2007, short-term financing was primarily used to fund ONEOK Partners’ capital projects. ONEOK Partners’ $598 million debt issuance, net of discounts, was used to repay borrowings under the ONEOK Partners Credit agreement and finance the $300 million acquisition of assets, before working capital adjustments, from a subsidiary of Kinder Morgan in October 2007.
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 ONEOK Partners 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 $1.4 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 ONEOK Partners Credit Agreement.
On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. With the settlement of the equity units, we received $402.4 million in cash, which we used to repay a portion of our commercial paper. We repaid a total of $641.5 million of our commercial paper during 2006. See Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion regarding the equity unit conversion.
In March 2006, our ONEOK Partners segment borrowed $33 million under the ONEOK Partners Credit Agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million.
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.
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.
In December 2005, we made an early redemption of our $300.0 million long-term notes. 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.
During 2007, we paid $20.1 million for the settlement of the forward purchase contract related to our stock repurchase in February and approximately $370 million for our stock repurchase in June. We paid $281.4 million to repurchase shares in August 2006. During 2005, we paid $233.0 million to repurchase 7.5 million shares. All of these stock repurchases were pursuant to the plans approved by our Board of Directors.
During 2007 and 2006, we paid $182.9 million and $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.
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, 2007. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of the 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 multiplying long-term debt by the respective coupon rates, adjusted for active swaps.
Operating Leases - Our operating leases include a gas processing plant, storage contracts, office space, pipeline equipment, rights-of-way and vehicles. Operating leases for ONEOK Partners exclude intercompany payments related to the lease of a gas processing plant.
In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term, set to expire on September 30, 2009. In addition, ONEOK Leasing Company has entered into a purchase agreement with the owner of ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building to a date on or before March 31, 2008. The total purchase price of approximately $48 million would include $17.1 million for the present value of the lease payments and the $30.9 million base purchase price. These amounts are included in the 2008 column above.
Firm Transportation Contracts - Our ONEOK Partners, Distribution and Energy Services segments are party to fixed-price transportation contracts. However, the costs associated with our Distribution segment’s contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above. Firm transportation agreements with ONEOK Partners segment’s natural gas gathering and processing joint-ventures require minimum monthly payments.
Financial and Physical Derivatives - These are obligations arising from our ONEOK Partners and Energy Services segment’s physical and financial derivatives, and are based on market information at December 31, 2007. Not included in these amounts are offsetting cash inflows from our Energy Services segment’s product sales and net positive settlements of $865 million at December 31, 2007. As market information changes daily and is potentially volatile, these values may change significantly. Additionally, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.
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 include purchases related to ONEOK Partners’ growth capital expenditures and other right of way commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.
FORWARD-LOOKING STATEMENTS
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,” “goal,” “forecast” and other words and terms of similar meaning.
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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the effects of weather and other natural phenomena on our operations, including energy sales and demand for our services and energy prices;
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competition from other United States 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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the uncertainty of estimates, including accruals and costs of environmental remediation;
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the timing and extent of changes in energy commodity prices;
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the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, and authorized rates or recovery of gas and gas transportation costs;
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impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
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changes in demand for the use of natural gas because of market conditions caused by concerns about global warming or changes in governmental policies and regulations due to climate change initiatives;
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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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actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;
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the results of administrative proceedings and litigation, regulatory actions and receipt of expected 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 gathering, 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 and outcome of pending and future litigation;
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the ability to market pipeline capacity on favorable terms, including the affects of:
- future demand for and prices of natural gas and NGLs;
- competitive conditions in the overall energy market;
- availability of supplies of Canadian and United States natural gas;
- availability of additional storage capacity;
- weather conditions; and
- competitive developments by Canadian and U.S. natural gas transmission peers;
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performance of contractual obligations by our customers, service providers, contractors and shippers;
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the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other 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, to promptly obtain all necessary materials and supplies required for construction, and to construct pipelines without labor or contractor problems;
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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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our ability to control operating costs;
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acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;
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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 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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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 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 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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our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing, storage, fractionation and transportation facilities;
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the composition and quality of the natural gas and NGLs 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 and fractionating NGLs;
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the impact of potential impairment charges;
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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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our ability to control construction costs and completion schedules of our pipelines and other projects; 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 natural gas 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 consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, store or use natural gas from inventory, and are exposed to commodity price risk. At December 31, 2007, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.
In addition, 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.
ONEOK Partners is also exposed to commodity price risk, primarily NGLs, as a result of receiving commodities in exchange for its gathering and processing services. To a lesser extent, ONEOK Partners is exposed to the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to its keep-whole processing contracts and the risk of price fluctuations and the cost of intervening transportation at various market locations. ONEOK Partners uses commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility in its natural gas gathering and processing business related to natural gas, NGL and condensate price fluctuations.
ONEOK Partners reduces its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its POP equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. This has the effect of converting ONEOK Partners’ gross processing spread risk to NGL commodity price risk and ONEOK Partners then uses financial instruments to hedge the sale of NGLs.
The following table sets forth ONEOK Partners’ hedging information for the year ending December 31, 2008.
ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at December 31, 2007, excluding the effects of hedging and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates the following:
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a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $1.7 million,
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a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.5 million, and
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a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.3 million.
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, a change in the gross processing spread may cause ethane to be sold in the natural gas stream, impacting gathering and processing margins, NGL exchange margins, natural gas deliveries and NGL volumes shipped.
Distribution
Our Distribution segment uses 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. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas cost mechanism.
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 $3.5 million, net of derivative instruments that have been declared as either fair value or cash flow hedges, and $15.7 million, net of deferred option premiums.
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 Derivatives - The following table provides details 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. Derivative instruments that have been declared as either fair value or cash flow 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 the Notes to Consolidated Financial Statements in this Annual Report on 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 $6.0 million and $12.5 million at December 31, 2007 and 2006, 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 decrease in VAR for 2007, compared with 2006, was due to lower commodity prices and decreased price volatility in 2007, particularly in the first quarter of 2007.
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, 2007, 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.
ONEOK Partners terminated two floating-rate swaps in 2007. The total value ONEOK Partners received for the terminated swaps was not material. At December 31, 2007, the interest rate on all of ONEOK Partners’ long-term debt was fixed.
At December 31, 2007, 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 $3.4 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 - See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of the impact of interest-rate swaps and net interest expense savings from terminated swaps.
Total net swap savings for 2007 were $8.2 million, compared with $7.6 million for 2006. Total swap savings for 2008 is expected to be $14.3 million.
CURRENCY RATE RISK
As a result of our Energy Services segment’s expansion into Canada, we are subject to currency exposure from our commodity purchases and sales 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, 2007 and 2006, our exposure to risk from currency translation was not material. We recognized currency translation gains of $4.1 million and $2.5 million during 2007 and 2006, respectively. At December 31, 2005, 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
To the Board of Directors and Shareholders
ONEOK, Inc.:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of income, shareholders' equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2007, and the results of their operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A in the Company's Form 10-K for the year ended December 31, 2007. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audit. 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
/s/ PricewaterhouseCoopers LLP
February 27, 2008
Tulsa, Oklahoma
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
ONEOK, Inc.:
We have audited the accompanying consolidated balance sheet of ONEOK, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the two-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 the results of their operations and their cash flows for each of the years in the two-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, “Employers’ 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.”
/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.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY 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 natural gas liquids systems that connect much of the natural gas and NGL supply in the Mid-Continent and Gulf Coast regions with key market centers in Conway, Kansas, Mont Belvieu, Texas, and Chicago, Illinois.
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, Accounting for Financially Settled Transactions 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 all derivative instruments at fair value. The fair value of a derivative instrument 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 nature of the risk being hedged and how we will determine the hedging instrument is effective. 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 a given period.
To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collars or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, condensate and fuel requirements. 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 accumulated 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.
Upon election, 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 are therefore exempt from fair value accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument is (i) held for trading purposes, (ii) financially settled, (iii) results in physical delivery or services rendered, and (iv) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows:
•
all financially settled derivative contracts are reported on a net basis,
•
derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis,
•
derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis, and
•
derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.
We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.
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.” 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 $443.0 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2007, of which $287.5 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 as of December 31, 2007 and 2006. 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.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. 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 required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 was effective for our year ended December 31, 2006, except for the measurement date change from September 30 to December 31, which will be effective for our year ending December 31, 2008.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal 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 additional discussion of contingencies.
Significant Accounting Policies
Consolidation - Our 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 Consolidated Balance Sheets 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) 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.
Short-Term Investments - Our short-term investments consist of auction-rate securities, which are corporate or municipal bonds that have underlying long-term maturities. The interest rates are reset through auctions that are typically held every 7-35 days, at which time the securities can be sold. Short-term investments in auction-rate securities are used as part of our cash management program. At December 31, 2007, we had no short-term investments.
Inventories - Materials and supplies are valued at average cost. Noncurrent natural gas is classified as property and valued at cost. For our ONEOK Partners segment, current natural gas and NGLs in storage are determined using the lower of cost or market method. Our Energy Services segment values current natural gas in storage using the lower of cost or market method. 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 $72.4 million and $45.4 million at December 31, 2007 and 2006, respectively, compared with its value under the LIFO method of $85.4 million and $60.7 million at December 31, 2007 and 2006, respectively.
As of January 1, 2008, Oklahoma Natural Gas is required to change from LIFO to the weighted-average cost methodology based on a change in state law. The impact of this change on our consolidated financial statements is immaterial, as the actual cost of gas is recovered from our rate payers through our purchased gas recovery mechanism.
Natural Gas Imbalances and Commodity Exchanges - Imbalances and NGL exchanges are valued at market or their contractually stipulated rate. Imbalances and NGL exchanges are settled in cash or made up in-kind, subject to the terms of the pipelines’ tariffs or by agreement.
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 it did not have a material impact on our results of operations or financial position.
Property - The following table sets forth our property, by segment, for the periods presented.
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.
Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.
At December 31, 2007, we had construction work in process of $954.3 million that had not yet been put in service and therefore was not being depreciated. Of this amount, $859.8 million was related to our ONEOK Partners segment, $51.3 million was related to our Distribution segment and $43.2 million was related to our Other segment.
Certain maintenance and repairs are charged directly to expense. Gains and losses from sales or transfers of an entire operating unit or system are recognized in income.
We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2007 was $15.7 million, which was recorded as a reduction to interest expense, and was not material in 2006 or 2005.
Regulated properties are stated at cost, which includes the equity portion of AFUDC. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded as a credit to the allowance for equity funds used during construction. Generally, the cost of property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation.
The average depreciation rates for our regulated property are set forth in the following table for the periods indicated.
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 natural gas gathering and processing, natural gas liquids gathering and fractionation, natural gas pipelines, and natural gas liquids pipelines operations. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through company facilities. ONEOK Partners’ natural gas liquids gathering and fractionation 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’ natural gas pipelines and natural gas liquids pipelines operations is recognized based upon contracted capacity and contracted 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. All natural gas residential distribution customers and some commercial customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month.
Our Energy Services segment 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 recorded at fair value. Demand payments received for a requirements contract are recognized in the period in which the service is provided. See Note D “Accounting Treatment” for additional information.
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 - Income taxes are accounted for using the provisions of Statement 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carry forward items based on income tax laws and rates existing at the time the temporary differences are expected to reverse. 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 was 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. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements.
We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada. No returns are currently under audit, and no extensions of statute of limitations have been requested or granted.
Regulation - Our distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. Other natural gas and natural gas liquids 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, 2007, we had regulatory assets that are being recovered through various rate cases in the amount of $309.4 million, included in other assets on our 2007 Consolidated Balance Sheet.
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 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 that have jurisdiction over our regulated operations have not required us to track this amount; rather these costs are addressed prospectively as depreciation rates and 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 and amortization to non-current liabilities in other deferred credits on our Consolidated Balance Sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore 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 consolidated 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.
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 fiscal year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.
Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that 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 purchased 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.
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.
Other
Fair Value Measurements - 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. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FASB Staff Position (FSP) 157-2, which delayed the effective date of Statement 157 for nonfinancial assets and liabilities. As of January 1, 2008, we have applied the provisions of Statement 157 to our financial instruments and the impact was not material. Under FSP 157-2, we will be required to apply Statement 157 to our nonfinancial assets and liabilities beginning January 1, 2009. We are currently reviewing the applicability of Statement 157 to our nonfinancial assets and liabilities as well as the potential impact on our consolidated financial statements.
In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159 and therefore there was no impact to our consolidated financial statements.
In April 2007, the FASB issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FIN 39-1 is effective for our year beginning January 1, 2008. We have reviewed the applicability of FIN 39-1 to our operations and its potential impact on our consolidated financial statements and have concluded the impact is immaterial.
Business Combinations - In December 2007, the FASB issued Statement 141R, “Business Combinations,” which will require most identifiable assets, liabilities, noncontrolling interest (previously referred to as minority interests) and goodwill acquired in a business combination to be recorded at full fair value. Statement 141R is effective for our year beginning January 1, 2009, and will be applied prospectively. We are currently reviewing the applicability of Statement 141R to our operations and its potential impact on our consolidated financial statements.
Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” which requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity. Statement 160 is effective for our year beginning January 1, 2009, and will require retroactive adoption of the presentation and disclosure requirements for existing minority interests. We are currently reviewing the applicability of Statement 160 to our operations and its potential impact on our consolidated financial statements.
Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2007 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
B. ACQUISITIONS AND DIVESTITURES
Acquisition of NGL Pipeline - In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan Energy Partners, L.P. (Kinder Morgan) for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of three refined petroleum products terminals and connecting pipelines. Financing for this transaction came from the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I for a discussion of the 2037 Notes. The working capital settlement has not been finalized; however, ONEOK Partners does not expect material adjustments.
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. Overland Pass Pipeline Company is building a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs, which can be increased to approximately 150 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have 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. This project has received the required approvals of various state and federal regulatory authorities, and ONEOK Partners is constructing the pipeline with start-up currently scheduled for the second quarter 2008.
As part of a long-term agreement, Williams dedicated its NGL production from two of its natural 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 currently estimated to cost approximately $535 million, excluding AFUDC. In addition, ONEOK Partners is investing approximately $216 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.
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 a total of 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, is 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, and an affiliate of TransCanada became operator of the pipeline in April 2007. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006.
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 accounted for on a retroactive basis to January 1, 2006.
Disposition of Spring Creek - In October 2005, we entered into an agreement to sell our Spring Creek power plant, located in Oklahoma, to Westar Energy, Inc. (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 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 MBbl/d 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 Venice Energy Services Company, L.LC. 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.
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.
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 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.
At the time of the sale, we retained a contract with the Oklahoma Municipal Power Authority (OMPA) that required us to provide OMPA with 75 megawatts of firm capacity per month for a monthly fixed charge of approximately $0.4 million through December 31, 2015. To fulfill our obligations under this contract, we entered into an agreement with Westar to purchase 75 megawatts of firm capacity on the same terms as our agreement with OMPA. In an arbitration ruling dated October 11, 2007, our contract with OMPA was terminated as of that date and we were awarded payment for our services through that date. We are currently evaluating our alternatives with respect to our contract with Westar.
These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our consolidated 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.
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 that 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 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 condensate, NGLs, purchase and sale commitments, fuel requirements, currency exposure, transportation and storage contracts, and natural gas 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 through the use of derivative instruments. With respect to the net open positions that exist within our marketing and 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 and processing, and natural gas liquids gathering 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.
Our Distribution segment also uses 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. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas cost mechanism.
Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. 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, then 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 by performing a regression analysis on our cash flow and fair value hedging relationships quarterly to ensure the hedge relationships are highly effective on a retrospective and prospective basis, as required by Statement 133.
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.
We evaluate 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” are used to determine the proper treatment. These activities and all financially settled derivative contracts are 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,” are used to determine the proper treatment. We account for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis. 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.
Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same cash flow statement category as the cash flows from the related hedged items.
Fair Value Hedges - In 2007 and prior years, we and ONEOK Partners terminated various interest-rate swap agreements. The net savings from the termination of these swaps are being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2007 for all terminated swaps was $10.3 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.
At December 31, 2007, the interest on $340 million of fixed-rate debt was swapped to floating using interest-rate swaps. The floating rate was based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through December 31, 2007, the weighted-average interest rate on the swapped debt increased from 6.44 percent to 6.74 percent. At December 31, 2007, we recorded a net liability of $1.5 million to recognize the interest-rate swaps at fair value. Long-term debt was decreased by $1.5 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 included losses of $5.3 million and $9.0 million for 2007 and 2006, respectively, and was not material in 2005.
In September 2007, our Energy Services segment was notified that a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company would be curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment that was impacted by the force majeure event resulted in a loss of approximately $5.5 million.
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 the cost of fuel used in transportation of natural gas. Accumulated other comprehensive income (loss) at December 31, 2007, includes gains of approximately $36.2 million, net of tax, related to these hedges that will be realized within the next 17 months as forecasted transactions affect earnings. If prices remain at current levels, we will recognize $40.2 million in net gains over the next 12 months, and we will recognize net losses of $4.0 million thereafter. In accordance with Statement 133, the actual gains or losses will be reclassified into earnings when the related physical transactions affect earnings.
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, condensate and NGL products and the gross processing spread. If prices remain at current levels, our ONEOK Partners segment will recognize $4.6 million in net losses, all of which will be recognized over the next 12 months.
For all of our segments, net gains and losses 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 our cash flow hedges resulted in gains of approximately $0.2 million and $15.0 million in 2007 and 2006, respectively, and losses of approximately $33.9 million in 2005. In the event that forecasted transactions do not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no losses in 2007, 2006 or 2005 due to the discontinuance of cash flow hedge treatment.
Fair Value - The following table represents the fair value of our energy marketing and risk management assets and liabilities for the periods indicated.
(a) - Other includes physical.
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. 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, 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 information represents the carrying amounts and estimated fair values of our financial instruments for the periods indicated, excluding energy marketing and risk management assets and liabilities, which are listed in the table above.
The approximate fair value of cash and cash equivalents, short-term investments, accounts and notes receivable and accounts and notes payable is equal to 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. The book value of our long-term debt was $4.64 billion and $4.05 billion at December 31, 2007 and 2006, respectively. The approximate fair value of our long-term debt was $4.75 billion and $4.09 billion at December 31, 2007 and 2006, respectively.
At December 31, 2007, our investment securities classified as available for sale had an aggregate fair value of $24.2 million. We reported $13.7 million and $12.6 million in accumulated other comprehensive income (loss) for net unrealized holding gains on available-for-sale securities in 2007 and 2006, respectively. For 2007 and 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.
E. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Activity - There was no change in the carrying amounts of goodwill during 2007. The following table reflects the changes in the carrying amount of goodwill for the period indicated.
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.
Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of December 31, 2007 and 2006.
Impairment Test - We apply the provisions of Statement 142, “Goodwill and Other Intangible Assets,” and perform our annual goodwill impairment testing on July 1. There were no impairment charges resulting from the July 1, 2007, impairment testing, and no events indicating impairment have occurred subsequent to that date.
Intangible Assets
Our ONEOK Partners segment had $287.5 million of intangible assets related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch, which are being amortized over an aggregate weighted-average period of 40 years. 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 both 2007 and 2006 was $7.7 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets for the periods presented.
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.
F. COMPREHENSIVE INCOME
The table below shows the gross amount of other comprehensive income (loss) and related tax (expense) 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 and B Convertible Preferred Stock - There are no shares of Series A or 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. If issued, holders of shares 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 shares of Series C have been issued.
Common Stock - At December 31, 2007, we had approximately 179 million shares of authorized and unreserved common stock available for issuance.
Stock Repurchase Plan - On May 17, 2007, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our currently issued and outstanding common stock. On June 28, 2007, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with Bank of America, N.A. (Bank of America) at an initial price of $49.33 per share for a total of $370 million. Bank of America borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by
Bank of America over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In September 2007, the accelerated share repurchase agreement with Bank of America was settled, which resulted in Bank of America delivering an additional 186,402 shares of our common stock to us at no additional cost. All shares under this accelerated repurchase agreement were recorded as treasury shares in our Consolidated Balance Sheet as of December 31, 2007. These transactions completed the plan approved by our Board of Directors and we have no remaining shares available for repurchase under our stock repurchase plan.
On August 7, 2006, under a previously authorized stock repurchase plan, 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. These shares were recorded as treasury shares in our Consolidated Balance Sheets. UBS borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was 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 could have been settled, at our option, in cash or in shares of our common stock. In February 2007, the forward purchase contract with UBS was settled for a cash payment of $20.1 million, which was recorded in equity.
In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchases were accounted for as two separate transactions: (i) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (ii) as a forward contract indexed to our common stock. Additionally, we classified the forward contracts as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.”
During 2005, we repurchased 7.5 million shares of our common stock under a previously authorized stock repurchase plan.
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2007, April 30, 2007, July 31, 2007, and October 31, 2007, were $0.34 per share, $0.34 per share, $0.36 per share and $0.36 per share, respectively. Additionally, a quarterly dividend of $0.38 per share was declared in January 2008, payable in the first quarter of 2008.
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.
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 an average interest rate of 5.00 percent at December 31, 2007, and there was none outstanding at December 31, 2006. ONEOK Partners’ short-term notes payable carried average interest rates of 5.40 percent and 6.75 percent at December 31, 2007 and 2006, respectively.
ONEOK Credit Agreement - In April 2006, we amended our 2004 $1.2 billion credit agreement (ONEOK 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 ONEOK 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 ONEOK 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 ONEOK 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. The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. At December 31, 2007, we were in compliance with these covenants. As of December 31, 2007, $1.0 billion was available under this agreement.
At December 31, 2007, we had $102.6 million commercial paper or short-term notes payable outstanding. At December 31, 2006, we had no commercial paper or short-term notes payable outstanding. We had $58.7 million and $58.5 million in letters of credit outstanding at December 31, 2007 and 2006, respectively.
ONEOK Partners Credit Agreement - In March 2007, ONEOK Partners amended and restated its revolving credit facility agreement (ONEOK Partners Credit Agreement), with several banks and other financial institutions and lenders in the following principal ways: (i) revised the pricing, (ii) extended the maturity by one year to March 2012, (iii) eliminated the interest coverage ratio covenant, (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1), (v) increased the swingline sub-facility commitments from $15 million to $50 million and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of ONEOK Partners’ consolidated indebtedness. The interest rates applicable to extensions of credit under this agreement are based, at ONEOK Partners’ 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, depending on ONEOK Partners’ current long-term unsecured debt ratings.
In July 2007, ONEOK Partners exercised the accordion feature in the ONEOK Partners Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion.
In December 2006, ONEOK Partners amended its 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 its Partnership Credit Agreement.
Under the ONEOK Partners Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for any approved capital projects) of no more than 5 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 5.5 to 1 for the three calendar quarters following the acquisition.
Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. ONEOK Partners was in compliance with these covenants at December 31, 2007. At December 31, 2007, ONEOK Partners had $100 million of borrowings outstanding under this agreement and $900 million was available.
In November 2007, ONEOK Partners entered into a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is being used and a $12 million Standby Letter of Credit Agreement with Royal Bank of Canada. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas.
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. All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.
The aggregate maturities of long-term debt outstanding for the years 2008 through 2012 are shown below.
Additionally, $182.9 million of our debt is callable at par at our option from now until maturity, which is 2019 for $92.0 million and 2028 for $90.9 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.
ONEOK Partners’ 2007 Debt Issuance - In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.
ONEOK Partners may redeem the 2037 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the 2037 Notes, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the 2037 Notes plus accrued and unpaid interest. The 2037 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 2037 Notes are non-recourse to ONEOK.
The net proceeds from the 2037 Notes, after deducting underwriting discounts and commissions and expenses, of $592.9 million were used to finance ONEOK Partners’ $300 million acquisition, before working capital adjustments, of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan and to repay debt outstanding under the ONEOK Partners Credit Agreement.
The terms of the 2037 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 Fourth Supplemental Indenture, dated September 28, 2007 (Indenture). 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 2037 Notes will mature on October 15, 2037. ONEOK Partners will pay interest on the 2037 Notes on April 15 and October 15 of each year. The first payment of interest on the 2037 Notes will be made on April 15, 2008. Interest on the 2037 Notes accrues from September 28, 2007, which was the issuance date of the 2037 Notes.
ONEOK Partners’ 2006 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 and future 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 $1.05 billion outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the ONEOK Partners 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 pays interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes was made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Debt Covenants - We have debt covenants in addition to the covenants discussed in “ONEOK Partners’ 2007 Debt Issuance” and “ONEOK Partners’ 2006 Debt Issuance” above. ONEOK Partners’ $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment grade rating is 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, 2036 and 2037 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, 2036 and 2037 to declare those notes immediately due and payable in full.
Guardian Pipeline Senior Notes - These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the $133.6 million in notes outstanding at December 31, 2007, range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent. Guardian Pipeline’s senior notes contain financial covenants that require the maintenance of a ratio of (i) 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 (ii) total indebtedness to EBITDAR of not greater than 5.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2007, Guardian Pipeline was in compliance with its financial covenants.
Unamortized Debt Premium, Discount and Expense - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.
J. EMPLOYEE BENEFIT PLANS
Retirement and Other Postretirement Benefit Plans
Retirement Plans - We have defined benefit retirement plans covering certain full-time employees. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a defined contribution 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.
Other Postretirement Benefit Plans - We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.
Measurement - We use a September 30 measurement date for 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 be effective for our year ending December 31, 2008. Statement 158 required us to recognize the overfunded or underfunded status of our plans as an asset or liability on our Consolidated Balance Sheets and to recognize changes in the funded status in accumulated other comprehensive income (loss) in the year in which the changes occur.
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 reflected in earnings.
Our regulated entities have historically recovered pension and other postretirement benefit costs, as determined by Statement 87, “Employers’ Accounting for Pensions,” and Statement 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively, through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postretirement benefit costs in our regulated entities’ cost of service. Accordingly, we have recorded a regulatory asset for the minimum liability associated with our regulated entities’ pension and other postretirement benefit obligations that otherwise would have been recorded in accumulated other comprehensive income.
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.
The accumulated benefit obligation for our pension plan was $759.2 million and $767.3 million at December 31, 2007 and 2006, respectively.
There are no plan assets expected to be withdrawn and returned to us in 2008.
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.
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income (loss) for 2007 related to our pension benefits and postretirement benefits.
The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense.
The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or 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.
We determine our overall expected long-term rate of return on plan assets assumption based on our review of historical returns and the building block and economic growth models from our consultants.
Our discount rates for 2007 and 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 but 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 that 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.
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 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 US and international equities, investments in various classes of debt securities, insurance contracts and venture capital. The target allocation for the 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 2007, $4.1 million and $7.6 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 2008 contributions will be $3.1 million for the pension plan and $11.0 million for the other postretirement benefit plan.
Pension and Other Postretirement Benefit Payments - For 2007, benefit payments for our pension and other postretirement benefit plans were $50.6 million and $15.5 million, respectively. The following table sets forth the pension benefits and postretirement benefit payments expected to be paid in 2008-2017.
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2007, and include estimated future employee service.
Other Employee Benefit Plans
Thrift Plan - We have a Thrift Plan covering all full-time employees. Employee contributions are discretionary. We match 100 percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $13.2 million, $12.8 million and $10.5 million in 2007, 2006 and 2005, 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 eligible 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. Our contributions made to the plan were $2.7 million, $1.6 million and $0.6 million in 2007, 2006 and 2005, respectively.
Employee Deferred Compensation Plan - The ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Our contributions made to the plan were $0.3 million, $0.4 million and $0.2 million in 2007, 2006 and 2005, respectively.
K. COMMITMENTS AND CONTINGENCIES
Operating 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. In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term set to expire on September 30, 2009. In addition, ONEOK Leasing Company has entered into a purchase agreement with the owner of ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building to a date on or before March 31, 2008. The total purchase price of approximately $48 million would include $17.1 million for the present value of the lease payments and the $30.9 million base purchase price. The $17.1 million amount is included in the 2008 amount in the table below.
If the purchase transaction does not occur, annual rent expense for the lease will be approximately $6.8 million in 2008 and 2009, and estimated future minimum rental payments for the lease will be $9.3 million in 2008 and 2009. Rent payments were $9.3 million in 2007, 2006 and 2005.
We have the right to sublet excess office space in ONEOK Plaza. We received rental revenue of $2.9 million in 2007, 2006 and 2005. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.6 million in 2008, $1.8 million in 2009 and $0.8 million in 2010 and 2011.
Future minimum lease payments under non-cancelable operating leases on a gas processing plant, storage contracts, office space, pipeline equipment, rights-of-way and vehicles are shown in the table below.
The amounts in the ONEOK column above include the following minimum lease payments relating to the lease of a gas processing plant for $24.2 million in 2008, $24.0 million in 2009, $24.2 million in 2010 and $30.6 million in 2011. We acquired the lease in a business combination and recorded a liability for uneconomic lease terms. 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. The amounts in the ONEOK Partners column above excludes intercompany payments relating to the lease of a gas processing plant.
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, NGLs, or refined products, 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. 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 seven sites and have commenced soil remediation on the other two sites. We have begun site assessment at the remaining site where no active remediation has occurred. Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there have been no material effects upon earnings during 2007, 2006 or 2005 related to compliance with environmental regulations.
To date, we have incurred remediation costs of $6.9 million and have accrued an additional $5.1 million related to the sites where soil remediation has yet to be completed. 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 ongoing and additional water monitoring and remediation, 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.
Legal Proceedings - We are a party to various litigation matters and claims that 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.
Other - As a result of an internal review of a transaction that was brought to the attention of one of our affiliates by a third party, we have commenced an internal review of transactions that may have violated FERC capacity release rules or related rules. While our internal review is ongoing, we believe it is likely that a limited number of these transactions will have violated FERC capacity release rules or related rules. We have notified the FERC of this review and expect to file a report with the FERC by mid-March 2008 concerning any violations. At this time, we do not believe that penalties, if any, associated with potential violations will have a material impact on our 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.
At December 31, 2007, ONEOK Partners had approximately $5.0 million of tax benefits available 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.
We had income taxes receivable of approximately $13.2 million and $70.0 million at December 31, 2007 and 2006, respectively.
M. SEGMENTS
Segment Descriptions - We have divided our operations into four reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (i) our ONEOK Partners segment gathers, processes, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs; (ii) our Distribution segment delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (iii) our Energy Services segment markets natural gas to wholesale and retail customers; and (iv) 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 also 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 2005 table 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 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.
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, 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 2007, 2006 and 2005, we had no single external customer from which we received 10 percent or more of our consolidated gross 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 $344.3 million, net margin of $274.0 million and operating income of $122.4 million.
(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 $335.9 million, net margin of $261.9 million and operating income of $240.1 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.
N. SUPPLEMENTAL CASH FLOW INFORMATION
The following table sets forth supplemental information relative to our cash flow for the periods indicated.
Cash paid for interest includes swap terminations, treasury rate-lock terminations and ineffectiveness of $22.6 million for the year ended December 31, 2005.
O. STOCK-BASED COMPENSATION
Equity Compensation Plan
The ONEOK, Inc. 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.
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. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants.
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. Awards granted in 2007 and 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 vesting 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 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 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 2007 and 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2007 and 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 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). 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. Awards granted in 2004 vested during 2007 with a performance factor of 150 percent and the grantee received two-thirds of the grant in shares of our common stock (equity awards) and one-third of the grant in cash (liability awards).
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, until grants have been made for all shares authorized under the DSCP. 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. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants. 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 zero percent to 22.6 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 $19.5 million, $28.8 million and $13.6 million 2007, 2006 and 2005, respectively, which includes $7.5 million, $11.2 million and $5.3 million of tax benefits, respectively. No compensation cost was capitalized for 2007, 2006 and 2005.
Cash received from the exercise of awards under all share-based payment arrangements was $7.4 million for 2007. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $4.6 million for 2007. No cash was used to settle the equity portion of the restricted stock unit and performance unit awards granted under share-based payment arrangements.
Stock Option Activity
The total fair value of stock options vested during 2007 was $1.0 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 $44.77, that would have been received by the option holders had all option holders exercised their options as of December 31, 2007.
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 10 years based upon experience to date and the make-up of the optionees. As of December 31, 2007, all stock options were fully vested and expensed. The following table sets forth various statistics relating to our stock option activity.
Restricted Stock Unit Activity
The total fair value of shares vested during 2007 was $8.3 million. As of December 31, 2007, there was $7.7 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables set forth activity and various statistics for the equity portion of the restricted stock unit awards.
The following table sets forth activity for the liability portion of the restricted stock unit awards.
Performance Unit Activity
The total fair value of shares vested during 2007 was $10.7 million. As of December 31, 2007, there was $10.8 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 1.2 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 2007, 2006 and 2005 grants at the grant date.
(a)
-
Volatility was based on historical volatility over three years using daily stock price observations.
(b)
-
Volatility was not a factor used for the 2005 grants.
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.
(a)
-
Performance awards granted in 2004 and released in 2007 were adjusted with a 150 percent performance factor; for the liability awards, this resulted in an additional 42,167 shares released to participants.
(a)
-
Volatility was based on historical volatility over three years using daily stock price observations.
(b)
-
Valuation for 2005 was based upon year-end stock price.
Employee Stock Purchase Plan
The total number of shares of our common stock available and remaining for issuance under our ONEOK, Inc. Employee Stock Purchase Plan (the ESPP) is approximately 0.6 million of the initially authorized and reserved 3.8 million shares. Subject to certain exclusions, all full-time employees are eligible to participate in the ESPP. 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 59 percent of employees participated in the plan in 2007, while 63 percent of employees participated in both 2006 and 2005. Under the plan, we sold 217,369 shares at $36.85 in 2007, 340,364 shares at $22.57 per share in 2006, and 289,558 shares at $22.57 per share in 2005.
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 and remaining for issuance under this program is approximately 56,000 of the initially authorized and reserved 200,000 shares.
Shares issued to employees under this program totaled 44,099, 40,705 and 32,734 for the years ended December 31, 2007, 2006 and 2005, respectively. Compensation expense related to the Employee Stock Award Plan was $2.2 million, $1.6 million and $1.1 million in 2007, 2006 and 2005, respectively.
Deferred Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Nonqualified 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 or Equity Compensation Plan. Shares are distributed to non-employee directors at the fair market value of our common stock at the date of distribution.
P. UNCONSOLIDATED AFFILIATES
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated.
(a)
-
ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering Company, L.L.C. As a result of the incentive, ONEOK Partners’ share of Lost Creek Gathering Company, L.L.C.’s income exceeds its 35 percent ownership interest.
(b)
-
Equity method goodwill (Note E) was $185.6 million at December 31, 2007 and 2006, respectively.
Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All 2007 and 2006 amounts in the table below are equity earnings from investments in our ONEOK Partners segment.
(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)
-
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.
Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.
Q. 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 4,601, 66,463 and 28,107 option shares excluded from the calculation of diluted EPS for 2007, 2006 and 2005, respectively, since their inclusion would be antidilutive.
R. 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 limited partner units.
As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners’ common units and generally have the same voting rights as the common units and are entitled to receive increased quarterly distributions and distributions on liquidation equal to 110 percent of the distributions paid with respect to the common units. On June 21, 2007, we, as the sole holder of ONEOK Partners Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.
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 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. The effect of any incremental income allocations for incentive distributions that are allocated to the general partner is calculated after the income allocation for the general partner’s partnership interest and before the income allocation to the limited partners.
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 2007 were $0.98 per unit, $0.99 per unit, $1.00 per unit, and $1.01 per unit, respectively.
In January 2008, ONEOK Partners declared a cash distribution of $1.025 per unit payable in the first quarter. On February 14, 2008, we received the related incentive distribution of $14.1 million for the fourth quarter of 2007, 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, we are restricted from the assets and cash flows from ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners based on the terms of its partnership agreement, and for the years ended December 31, 2007, 2006 and 2005, cash distributions declared from ONEOK Partners to us totaled $207.4 million, $145.1 million and $10.8 million, respectively. See Note M for more information on ONEOK Partners results.
Affiliate Transactions - We have certain transactions with our ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment. In addition, a large portion of ONEOK Partners’ revenues from its natural gas pipelines businesses are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ natural gas transportation and storage services.
As part of the transaction between us and ONEOK Partners, ONEOK Partners acquired certain contractual rights to the 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. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant.
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.
S. 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.
Total revenues and net margin for the first and second quarters in the tables above were restated to be consistent with the classification used in our September 30, 2007 Quarterly Report on Form 10-Q and in this Annual Report on Form 10-K. The change was not material.
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 Exchange 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, 2007, 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, 2007.
Our internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers 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 year ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting as described below.
In September 2007, we implemented a new software system to support our accounting for hedging instruments. This system replaced a manually intensive process for reviewing and calculating hedge ineffectiveness.
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 2008 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 2008 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 2008 definitive Proxy Statement and is incorporated herein by this reference.
Nominating Committee Procedures
Information concerning the nominating committee procedures is set forth in our 2008 definitive Proxy Statement and is incorporated herein by this reference.
Audit Committee
Information concerning the Audit Committee is set forth in our 2008 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 2008 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 2008 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 2008 definitive Proxy Statement and is incorporated herein by this reference.
Security Ownership of Management
Information on security ownership of directors and officers is set forth in our 2008 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 2008 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 2008 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
2.1
Purchase and Sale Agreement by and between TransCan Northwest Border Ltd. and Northern Plains Natural Gas Company, LLC, dated February 14, 2006 (incorporated by reference from Exhibit 10.30 to our Form 10-K for the year ended December 31, 2005, filed March 13, 2006).
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.