ITEM 1. BUSINESS
GENERAL
ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.” We own and manage natural gas gathering, processing, storage and interstate and intrastate pipeline assets and natural gas liquids gathering and distribution pipelines, storage and fractionators, connecting much of the natural gas and NGL supply in the Mid-Continent region with key market centers. We also own a 50 percent equity interest in a leading transporter of natural gas imported from Canada into the United States.
DESCRIPTION OF BUSINESS SEGMENTS
Our operations are divided into four strategic business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, which include the following:
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our Gathering and Processing segment, which primarily gathers and processes raw natural gas;
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our Natural Gas Liquids segment, which primarily gathers, treats and fractionates raw NGLs and stores and markets purity NGL products;
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our Pipelines and Storage segment, which primarily operates regulated intrastate natural gas transmission pipelines, natural gas storage facilities and regulated natural gas liquids gathering and distribution pipelines; and
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our Interstate Natural Gas Pipelines segment, which primarily operates our regulated interstate natural gas transmission pipelines.
For financial and statistical information regarding our business segments, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. See Note M of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of changes in reportable business segments, as well as sales to unaffiliated customers, operating income and total assets by business segment.
Partnership Structure
We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP, which consists of six members, three of whom qualify as independent, under the listing standards of the NYSE and also serve on the Audit Committee of ONEOK Partners GP. ONEOK Partners GP is a wholly owned subsidiary of ONEOK. ONEOK owns a 45.7 percent aggregate equity interest in us.
Business Strategy
Our primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distributions over time. Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions.
We focus on expanding and acquiring assets in the United States related to energy transportation, gathering, processing, fractionation, storage and marketing that will utilize our core competencies, minimize commodity price risk and provide immediate cash flow. We finance our acquisitions and capital expenditures with a mix of operating cash flows, debt and equity.
Our acquisition of assets from ONEOK, described below, complemented our core competencies related to energy services and diversified our portfolio of assets. The assets we acquired from ONEOK enabled us to enter into energy related businesses in the well-established Mid-Continent region and key natural gas liquids markets in Kansas and Texas. In addition, our expanded asset portfolio positions us for future organic growth projects, which we believe currently offer the most attractive growth opportunities.
SIGNIFICANT DEVELOPMENTS IN 2006
In April 2006, we acquired certain companies comprising ONEOK’s former gathering and processing, natural gas liquids, and pipelines and storage segments, collectively referred to as the “ONEOK Energy Assets” from ONEOK, the parent company of our general partner, in a series of transactions collectively referred to as the “ONEOK Transactions,” which are described
in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments.” The ONEOK Energy Assets are consolidated with our legacy assets and are reported in our consolidated financial statements as of January 1, 2006.
In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines and agreed to transfer the responsibility for operations of Northern Border Pipeline to an affiliate of TransCanada effective April 1, 2007. After the sale, we have a 50 percent ownership interest in Northern Border Pipeline.
In April 2006, ONEOK acquired a 0.35 percent general partner interest in us from TransCanada. As a result, ONEOK now owns our entire 2 percent general partner interest.
In April 2006, we acquired the 66 2/3 percent interest in Guardian Pipeline not previously owned by us increasing our ownership interest to 100 percent.
In May 2006, we 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 will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the Mid-Continent natural gas liquids market center in Conway, Kansas.
NARRATIVE DESCRIPTION OF BUSINESS
Gathering and Processing
Business Strategy - We seek to reduce costs, streamline operations and increase facility utilization of our natural gas gathering and processing operations. We pursue growth of our gathering network through additional well connections, consolidation and acreage dedications, and facility expansions in new production areas. We also seek to restructure contracts at the end of their term to mitigate commodity price exposure and offset increased operating costs.
Segment Description - As part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments,” we acquired all of ONEOK’s natural gas gathering and processing assets and combined them with our legacy gathering and processing segment assets.
Our Gathering and Processing segment gathers and processes raw natural gas. We generally gather and process gas under the following types of contracts.
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Percent of Proceeds (POP) - Under a POP contract, we retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. POP contracts expose us to both natural gas and NGL commodity price risk, but economically align us with the producer because we both benefit from higher commodity prices. There are a variety of factors that directly affect our POP margins, including:
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the percentages of products retained that represent our equity NGL, condensate and natural gas sales volumes,
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transportation and fractionation rates incurred on the NGLs, and
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the natural gas, crude oil and NGL prices received for our equity products retained.
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Fee - Under a fee contract, we are paid a fee for the services provided on a basis such as Btus gathered, compressed and/or processed. The wellhead volume and fees received for the services provided are the main components of the margin for this type of contract. The producer may take its NGLs and natural gas in kind or receive its proceeds from our sale of the commodities. This type of contract exposes us to minimal commodity price risk but exposes us to volumetric risk. Our POP and keep-whole contracts also typically include fee provisions.
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Keep-Whole - Under a keep-whole processing contract, we extract NGLs from raw natural gas and return to the producer volumes of merchantable natural gas containing the same amount of Btus as the raw natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed as NGLs through the gathering and processing operation, commonly referred to as “shrink.” Under index-based purchase agreements, we purchase natural gas that we consume in processing at the wellhead and we typically bear the full cost of the plant fuel and shrink, with the excess natural gas being sold monthly at index-based prices. By using this contract type, the producer is kept whole on a Btu basis. This type of contract exposes us to the keep-whole spread, or gross processing spread, which is the relative difference in the economic value between NGLs and natural gas on a Btu basis. The main factors that affect our keep-whole margins include:
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shrink,
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plant fuel consumed,
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transportation and fractionation costs incurred on the NGLs,
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gross processing spread, and
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the natural gas, crude oil and NGL prices received for products sold.
Operating income from our Gathering and Processing segment was 45.5 percent, 17.4 percent and 11.2 percent of our consolidated operating income excluding the gain on sale of assets in 2006, 2005 and 2004, respectively. Operating revenue of this segment is derived primarily from POP and fee contracts. We use derivative instruments to mitigate our sensitivity to fluctuations in the price of natural gas, condensate and NGLs. Our Gathering and Processing segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for 35 percent of our Gathering and Processing segment’s revenues in 2006. Our Gathering and Processing segment had no intersegment sales in 2005 or 2004. A portion of our revenues are from ONEOK and its affiliates.
Market Conditions and Seasonality - Supply - Natural gas supply is affected by rig availability, operating capability, and producer drilling activity, which is sensitive to commodity prices, geological success, available capital and regulatory control. Relatively high natural gas and crude oil prices, as well as favorable long-term projections of U.S. demand, continued to drive increased drilling in 2006 in the Mid-Continent and Rocky Mountain regions, which are our primary supply regions.
In the Mid-Continent region, the gathering and processing assets we acquired in the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas are well established. However, we anticipate continuing volumetric declines in certain fields that supply our gathering and processing operations. Additionally, there is excess processing capacity, particularly in the Hugoton production region around the Bushton Gas Processing Plant (the Bushton Plant), which does not have the ability to recover as many NGLs, such as ethane, putting the plant at an economic disadvantage to cryogenic plants. On January 1, 2007, the Bushton Plant was temporarily idled. See discussion on page 25.
In the Williston Basin, we connected more wells in 2006 than in prior years as a result of increased drilling activity. Transportation and refining capacity constraints for crude oil continue to only moderately impact natural gas production in the Williston Basin. Further development of the Big George coals, located in the center of the Powder River Basin, resulted in greater volumes during 2006, compared with 2005, for our wholly owned assets and joint-venture interests in Bighorn Gas Gathering and Fort Union Gas Gathering.
Demand - Demand for gathering and processing services is typically aligned with the supply of natural gas, which generally flows from a producing area at a relatively steady but gradually declining pace over time unless new reserves are added. Our plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing, within limits, the temperature and pressure at which raw natural gas is processed, we can produce more of a specific commodity that has the most favorable price or price spread.
Commodity Prices - In recent years, crude oil, natural gas and NGL prices have been volatile due to market conditions. Storage injection and withdrawal rates, as well as available storage capacity, can also have an impact on commodity prices. We are exposed to market risk associated with adverse changes in commodity prices. Our primary exposures arise from the relative price differential between natural gas and NGLs with respect to our keep-whole processing contracts and the sale of natural gas, NGLs and condensate with respect to our POP contracts. To a lesser extent, we are exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations as well as demand for our products by the petrochemical industry and others.
Seasonality - Some of this segment’s products are subject to weather-related seasonal demand. Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses. Warm temperatures typically drive demand for natural gas used for gas-fired electric generation used to cool residential and commercial properties. During periods of peak demand for a certain commodity, prices for that product typically increase, which influences processing decisions.
Competition - The gathering and processing business remains relatively fragmented despite significant consolidation in the industry. We compete for natural gas supplies with major integrated exploration and production companies, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers, and independent processors and marketers in the Mid-Continent and Rocky Mountain regions.
Due to the unprecedented strength of the energy commodity market in the past two years, gathering and processing rates have become increasingly competitive. As a result, we may not be successful in obtaining new natural gas supplies to offset declines and may lose some existing supplies to competitors. We are responding to these industry conditions by making capital investments to improve plant processing flexibility and reduce operating costs, evaluating consolidation opportunities to maximize earnings, selling assets in non-core operating areas and renegotiating unprofitable contracts. Contracts covering approximately 47 percent of the volumes under keep-whole contracts contain language that effectively converts these contracts into fee contracts when the keep-whole spread is negative. It is our goal to have such conditioning language in 75 percent of our keep-whole contracts by volume to mitigate the impact of an unfavorable gross processing spread, and to renegotiate any under-performing gas purchase, gathering and processing contracts.
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 our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in removing NGLs and, therefore, we believe, 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 gathering and transmission facilities on a fact-specific basis. We believe our gathering facilities and operations meet the criteria used by the FERC for non-jurisdictional gathering facility status. We can transport residue gas from our plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.
Oklahoma and Kansas also have statutes regulating, to 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.
Natural Gas Liquids
Business Strategy - We seek to maximize our value by increasing facility utilization and efficiently managing the operating costs of our natural gas liquids assets, which consist of facilities that gather, fractionate and treat NGLs and store NGL purity products in the Mid-Continent and Gulf Coast areas.
Segment Description - As part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments,” we acquired all of ONEOK’s natural gas liquids assets and created a new segment that consists solely of these newly acquired natural gas liquids assets.
Our Natural Gas Liquids segment gathers, stores, fractionates and treats raw NGLs produced by natural gas processing plants located in Oklahoma, Kansas and the Texas panhandle. We connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key NGL market centers in Conway, Kansas and Mont Belvieu, Texas.
Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, raw form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates the raw NGL stream into marketable products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products are then stored and/or distributed to our customers, such as petrochemical plants, heating fuel users and motor gasoline manufacturers.
Operating revenue of this segment is derived primarily from exchange services, optimization and isomerization.
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Our exchange services business collects fees to gather, fractionate and treat raw NGLs thereby converting them into NGL purity products that are stored and shipped to a market center or customer-designated location.
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Our optimization business utilizes our asset base, contract portfolio and market knowledge to capture locational and seasonal price spreads. We move purity NGL products between Conway, Kansas and Mont Belvieu, Texas in order to capture the locational price spreads between the two market centers. Our NGL storage facilities in the Mid-Continent and Gulf Coast regions are used to capture seasonal price variances.
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Our isomerization business captures the price spread when normal butane is converted into the more valuable iso-butane at an isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to upgrade the octane of motor gasoline.
Operating income from our Natural Gas Liquids segment was 22.4 percent of our consolidated operating income excluding the gain on sale of assets in 2006. Our Natural Gas Liquids segment had no single external customer from which it received 10 percent or more of consolidated revenues.
Market Conditions and Seasonality - Supply - Supply for our Natural Gas Liquids segment depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production, primarily in the Mid-Continent region, and the liquids content of the natural gas that is produced and processed. Our Mont Belvieu fractionation operation receives NGLs from a variety of processors and pipelines located in the Gulf Coast, west and central Texas, and the Rocky Mountain regions.
Our NGL gathering pipelines are also affected by operational or market-driven changes that impact the output of natural gas processing plants to which they are connected. The differential between the price of NGLs and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas and the differential in the composite price of NGLs and the price of natural gas, may influence processing plant output. This differential may impact the volume of natural gas and NGLs injected or withdrawn from storage and the volume of natural gas and NGLs shipped through the system. Typically, the forward price of ethane compared with the forward price of natural gas provides minimal or no processing spread. However, as the prices settle, the price of ethane to natural gas has historically provided a positive processing spread. For most of 2006, ethane values remained above those of natural gas on a relative price basis, which resulted in ethane recovery from processing plants that deliver to our natural gas liquids gathering pipelines.
Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations impacts the volume of raw NGLs produced by processing plants, thereby affecting the demand for NGL gathering and fractionation services. Natural gas and propane are subject to weather-related seasonal demand. Other products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as iso-butane and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, ethane, and an ethane/propane mix. This ethane/propane mix is used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.
Commodity Prices - In recent years, crude oil, natural gas and NGL prices have been volatile due to market conditions. We are exposed to market risk associated with adverse changes in the price of NGLs, the basis differential between the Mid-Continent and Gulf Coast regions, and the relative price differential between natural gas, raw NGLs and individual NGL purity products, which impact our NGL purchases, sales and storage revenue. When natural gas prices are higher relative to NGL prices, NGL production may decline, which could negatively impact our exchange services revenue. When the basis differential between the Mid-Continent and Gulf Coast regions is narrow, optimization opportunity and margins may decline. NGL storage revenue may be impacted by price volatility and forward pricing of natural gas liquids physical contracts versus the price of NGLs on the spot market.
Seasonality - Some NGL products produced by our natural gas liquids facilities are subject to weather-related seasonal demand, such as propane, which is primarily used to heat residential properties during the winter heating season. Demand for iso-butane and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, may also be subject to some seasonality when automotive travel is higher.
Competition - We compete with other fractionators and gatherers for natural gas liquids supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions. We are making capital investments to improve plant processing and fractionation flexibility and reduce operating costs so that we may compete more effectively. Information about our Natural Gas Liquids segment’s projected capital expenditures is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Liquidity and Capital Resources - Capital Expenditures.”
Government Regulations - Revenues generated by our proprietary pipelines in both Oklahoma and Kansas are not regulated by the FERC or those states’ respective corporation commissions.
Pipelines and Storage
Business Strategy - We seek to maintain a competitive cost structure and increase facility utilization of our pipelines and storage operations. We pursue growth of our existing pipelines and storage assets.
Segment Description - As part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments,” we acquired all of ONEOK’s pipeline and storage assets and created a new segment that consists solely of these newly acquired assets.
Our Pipelines and Storage segment operates intrastate natural gas transmission pipelines, natural gas storage facilities, regulated natural gas liquids gathering and distribution pipelines, and non-processable natural gas gathering facilities. We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act.
In Oklahoma, we have access to the major natural gas producing areas and transport natural gas and NGLs throughout the state. We also have access to the major natural gas producing area in south central Kansas. In Texas, we 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. Our natural gas liquids gathering connections deliver raw NGLs gathered in Oklahoma, Kansas and the Texas panhandle to our fractionation facilities and to our natural gas liquids distribution pipelines, which provide access to two of the main NGL market centers in Conway, Kansas and Mont Belvieu, Texas.
We own or reserve storage capacity in 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.
We operate approximately 2,400 miles of FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas. Our natural gas liquids pipelines deliver NGLs gathered from natural gas processing plants located in these states to fractionation facilities in Medford, Oklahoma, Hutchinson and Conway, Kansas, and Mont Belvieu, Texas. Our natural gas liquids distribution pipelines move products from Oklahoma and Kansas to the market centers of Conway, Kansas and Mont Belvieu, Texas.
Our transportation contracts for our regulated natural gas and natural gas liquids pipelines are based upon rates stated in our tariffs. Tariffs specify the maximum rates customers can be charged, which can be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established in FERC or appropriate state jurisdictional agency proceedings known as rate cases. In Texas and Kansas, natural gas storage service is a fee business that may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas gathering and natural gas storage operations are not subject to rate regulation and have market-based rate authority from FERC for certain types of services.
The Pipelines and Storage segment’s revenues are typically derived from fee services from 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. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store and/or we may retain a specified volume of natural gas in-kind for fuel. Under the firm service contract, the customer is generally guaranteed access to the capacity they reserved.
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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. Interruptible service customers are typically assessed fees, such as a commodity charge, based on their actual usage and/or we may retain a specified volume of natural gas in-kind for fuel. Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available.
A portion of our revenue is derived from services provided to ONEOK and its affiliates. Operating income excluding the gain on sale of assets from our Pipelines and Storage segment was 27.0 percent of our consolidated operating income excluding the gain on sale of assets in 2006. Our Pipelines and Storage segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for 25 percent of our Pipelines and Storage segment’s revenues in 2006.
Market Conditions and Seasonality - Supply - The supply of natural gas and NGLs to our pipelines and storage assets currently depends on the pace of natural gas drilling activity by producers and the decline rate of existing production in the major natural gas production areas in the Mid-Continent region, including the Anadarko Basin, Hugoton Basin, Central Kansas Uplift Basin and Permian Basin. United States natural gas drilling rig counts have increased in 2006 compared with 2005.
The natural gas liquids gathering pipelines are also affected by operational or market-driven changes that impact the output of natural gas processing plants to which they are connected. The differential between the price of NGLs and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas and the differential in the composite price of NGLs and the price of natural gas, may influence processing plant output. This differential may impact
the volume of natural gas and NGLs injected or withdrawn from storage and the volume of natural gas and NGLs shipped through the system. Typically, the forward price of ethane compared with the forward price of natural gas provides minimal or no processing spread. However, as the prices settle, the price of ethane to natural gas has historically provided a positive processing spread. Ethane prices generally remained above natural gas prices on a relative basis in 2006.
Demand - Demand for pipeline transportation service and natural gas storage is directly related to demand for natural gas and NGL products in the markets the pipelines and storage facilities serve, and is affected by the economy, natural gas and NGL price volatility, and weather. The strength of the economy directly impacts manufacturing and industrial companies that rely on natural gas and NGL products. Volatility in the natural gas market can influence customers’ decisions related to natural gas storage injection and withdrawal activity. The effect of weather on our pipelines and storage operations is discussed below under “Seasonality.”
Commodity Prices - We are exposed to market risk when existing contracts expire and are subject to renegotiation with customers that have competitive alternatives and analyze the market price spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. We may also be subject to market risk associated with the relative price differential between natural gas and NGL prices with respect to our natural gas liquids pipeline revenue. Natural gas storage revenue is impacted by the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market. Our fuel costs and the value of the retained fuel in-kind are also impacted by adverse changes in the commodity price of natural gas.
Seasonality - Demand for natural gas is seasonal. Weather conditions throughout the United States can significantly impact regional natural gas supply and demand. High temperatures can increase demand for gas-fired electric generation to cool residential and commercial properties. Low precipitation levels can impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region. Cold temperatures can lead to greater demand for our transportation services due to increased demand for natural gas. As previously described for our Natural Gas Liquids segment, some NGL products are subject to weather-related seasonal demand, resulting in transportation for these products also being subject to weather-related seasonal demand.
To the extent that pipeline capacity is contracted under firm service transportation agreements, revenue, which is generated primarily from demand charges, is not significantly impacted by seasonal throughput variations. However, when transportation agreements expire, seasonal demand can impact re-contracting of firm service transportation capacity.
Natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric power generation users. While most of our storage capacity is contracted under term agreements, there is a seasonal market for capacity not under term agreements.
Competition - Our natural gas and natural gas liquids pipelines and storage facilities compete with other pipeline companies and other storage facilities for the natural gas and NGL supply in the Mid-Continent region and for markets in the Mid-Continent and Gulf Coast regions. Competition among pipelines and natural gas storage facilities is based primarily on fees for service and proximity to natural gas supply areas and markets. 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.
Government Regulation - Our natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. We have flexibility in establishing natural gas transportation rates with customers. However, there is a maximum rate that we can charge our customers in Oklahoma and Kansas. Our natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas are interstate pipelines regulated by the FERC and the Office of Pipeline Safety. We transport raw NGLs and NGL products pursuant to filed tariffs.
Interstate Natural Gas Pipelines
Business Strategy - We focus on safe, efficient and reliable operations and increasing throughput on our interstate pipelines. We intend to continue to provide cost-effective transportation for natural gas to the Midwestern United States. We seek growth of our interstate natural gas pipelines through incremental projects that access new market areas and are supported by long-term transportation contracts.
Segment Description - Our Interstate Natural Gas Pipelines segment consists of our regulated interstate natural gas transmission pipelines, which are:
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Guardian Pipeline;
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Midwestern Gas Transmission;
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Viking Gas Transmission;
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OkTex Pipeline, and
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our 50 percent interest in Northern Border Pipeline.
In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada will become operator of the pipeline in April 2007. As a result of the transaction, we deconsolidated Northern Border Pipeline, effective January 1, 2006, and reflect it as an investment in unconsolidated affiliates on our 2006 Consolidated Balance Sheet. Our share of Northern Border Pipeline’s operating results is reported as equity earnings from investments in our 2006 Consolidated Statement of Income.
In April 2006, we acquired the 66 2/3 percent interest in Guardian Pipeline not previously owned by us increasing our ownership to 100 percent. Guardian Pipeline is consolidated in our financial statements as of January 1, 2006. Previously, it was reflected as an investment under the equity method.
Operating revenue for this segment is derived from transportation contracts at rates that are stated in our FERC-regulated tariffs. Tariffs specify the maximum rates we can charge our customers and the general terms and conditions for natural gas transportation service on our pipelines. Our pipelines’ tariffs also allow for services to be provided under negotiated and discounted rates. Transportation rates are established periodically in FERC proceedings known as rate cases. Our transportation contracts include specifications regarding the receipt and delivery of natural gas at points along the pipeline systems. The type of transportation contract, either firm or interruptible service, determines the basis by which each customer is charged.
The Interstate Natural Gas Pipelines segment’s revenues are typically derived from fee services from the following contract types.
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Firm Service - Customers can reserve a fixed quantity of pipeline 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. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport and/or we may retain a specified volume of natural gas in-kind for fuel. Under the firm service contract, the customer is generally guaranteed access to the capacity they reserved.
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Interruptible Service - Customers with interruptible service transportation agreements may utilize available capacity after firm service requests are satisfied or on an as available basis. Interruptible service customers are typically assessed fees, such as a commodity charge based on their actual usage, and/or we may retain a specified volume of natural gas in-kind for fuel. Under the interruptible service contract, the customer is not guaranteed use of our pipeline facilities unless excess capacity is available.
Operating income excluding the gain on sale of assets from our Interstate Natural Gas Pipelines segment was 11.3 percent, 83.4 percent and 91.2 percent of our consolidated operating income excluding the gain on sale of assets in 2006, 2005 and 2004, respectively. In 2006, 86 percent of our Interstate Natural Gas Pipelines segment’s revenue was derived from firm and interruptible service fees. Our Interstate Natural Gas Pipelines segment had no single external customer from which it received 10 percent or more of consolidated revenues.
Market Conditions and Seasonality - Supply - The supply of natural gas for Viking Gas Transmission and Northern Border Pipeline is primarily from Canada. A significant portion of the natural gas supply of Guardian Pipeline and Midwestern Gas Transmission originates in Canada. For these reasons, the continuous supply of Canadian natural gas is crucial to our long-term financial condition. Significant factors that can impact the supply of Canadian natural gas transported by our pipelines are the Canadian natural gas available for export, Canadian storage capacity and demand for Canadian natural gas in other U.S. consumer markets. We expect that Canadian natural gas export volumes may decrease in 2007 compared with 2006. Industry analysts are predicting a decline in the available supply of Canadian natural gas of as much as one Bcf/d, approximately 11 percent of total production, as drilling activity slows and natural gas demand in Canada grows. However, if new pipeline projects associated with the Mackenzie Delta in northern Canada and Alaska are constructed, they could provide access to significant new supply sources.
Demand - Demand for natural gas transportation service on our pipelines is directly related to demand for natural gas in the markets that our customers serve. Factors that may impact demand for natural gas include weather conditions, economic
conditions, government regulation, availability and price of alternative energy sources, fuel conservation measures and technological advances in fuel economy and energy generation devices. Furthermore, factors that may impact demand for natural gas transportation service on our pipelines include the ability and willingness of natural gas shippers to utilize our pipelines over alternative pipelines, transportation rates and the volume of natural gas delivered to Midwestern U.S. markets from other supply sources and storage facilities.
The Interstate Natural Gas Pipelines segment’s primary exposure to market risk occurs when existing transportation contracts expire and are subject to renegotiation. Customers with competitive alternatives analyze the market price spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. In addition to general demand for natural gas, regional economic conditions, climate, trends in production, available pipeline capacity and natural gas storage inventories in each market area can also impact the basis differential and affect demand for transportation service on our pipelines.
Government Regulation - Our 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 this business segment, including:
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transportation of natural gas;
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rates and charges;
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terms of service, including credit worthiness requirements;
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construction of new facilities;
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extension or abandonment of service and facilities;
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accounts and records;
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depreciation and amortization policies;
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acquisition and disposition of facilities; and
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initiation and discontinuation of services.
Other
Segment Description - Our Other segment includes Black Mesa which is a coal slurry pipeline that did not operate during 2006. On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of the Mohave Generating Station (Mohave) expired and our coal slurry pipeline operations were shut down as expected. In June 2006, Southern California Edison Company (SCE), a 56 percent owner of Mohave, completed a comprehensive study of the water source, coal supply and transportation issues and announced that it would no longer pursue the resumption of plant operations. In February 2007, another Mohave co-owner, Salt River Project, announced it was ending its efforts to return the plant to service. Negotiations between various parties involved with Black Mesa are ongoing.
ENVIRONMENTAL AND SAFETY MATTERS
We are subject to multiple environmental laws and regulations affecting many aspects of our 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 our 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.
Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2006, 2005 or 2004 related to compliance with environmental regulations.
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. Pipeline companies are required to perform the initial integrity assessments within 10 years of the date of enactment, which was December 2003, and perform subsequent integrity assessments on a seven-year cycle. We are on schedule to meet the required assessment of 50 percent of the areas by the end of 2007.
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.
EMPLOYEES
We do not directly employ any of the persons responsible for managing or operating us or for providing us with services related to our day-to-day business affairs. We have a service agreement with ONEOK, ONEOK Partners GP and NBP Services (the Services Agreement) that replaced the Administrative Services Agreement between us and NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK will provide to us at least the type and amount of services that it provides to its other affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP will continue to operate our interstate natural gas pipeline assets according to each pipeline’s operating agreement, except for the operating agreement between ONEOK Partners GP and Northern Border Pipeline, which will terminate effective April 1, 2007. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. As of January 31, 2007, we utilized the services of 1,219 full-time employees in addition to the other resources provided by ONEOK and its affiliates. Black Mesa continues to employ nine employees to support Black Mesa’s standby operations.
AVAILABLE INFORMATION
You can access financial and other information at our website at www.oneokpartners.com. We make available on our website, free of charge, copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and reports of holdings of our securities filed by our officers and directors under Section 16 of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct, Governance Guidelines, Accounting and Financial Reporting Code of Ethics, Partnership Agreement and written charter of our Audit Committee 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 the information under “Forward-Looking Statements” that are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
RISKS INHERENT IN OUR BUSINESS
The volatility of natural gas and NGL prices could adversely affect our cash flow.
A significant portion of our natural gas gathering and processing revenue is derived from the sale of commodities received as payment for our gathering and processing services. Additionally, certain of our gas gathering and processing assets in Oklahoma and Kansas have keep-whole processing contracts, under which we extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of Btus that were removed as NGLs. This type of contract exposes us to the keep-whole spread, or gross processing spread, which is the relative difference in the prices of natural gas and NGLs on a Btu basis. As a result, we are sensitive to natural gas and NGL price fluctuations. Natural gas and NGL prices have been and are likely to continue to be volatile in the future. High natural gas and NGL prices and processing spreads may not continue and could drop precipitously in a short period of time. The prices of natural gas and NGLs are subject to wide fluctuations in response to a variety of factors beyond our control, including the following:
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relatively minor changes in the supply of, and demand for, domestic and foreign natural gas and NGLs;
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market uncertainty;
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the availability and cost of transportation capacity;
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the level of consumer product demand;
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geopolitical conditions impacting supply and demand for natural gas and crude oil;
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weather conditions;
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domestic and foreign governmental regulations and taxes;
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the price and availability of alternative fuels;
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speculation in the commodity futures markets;
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overall domestic and global economic conditions;
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the price of natural gas and NGL imports; and
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the effect of worldwide energy conservation measures.
These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of natural gas and NGLs. As natural gas and NGL prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, production and related volumes could also decline.
Our inability to execute growth and development projects and acquire new assets could reduce cash distributions to unitholders.
Our primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distributions over time. Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Accordingly, if we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations.
We do not fully hedge against price changes in commodities. This could result in decreased revenues, increased costs and lower margins, adversely affecting our results of operations.
Our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs, crude oil and power prices. Market risk refers to the risk of loss arising from adverse changes in commodity energy prices. Our primary exposure arises from the difference between natural gas and NGL prices with respect to our keep-whole processing agreements, commodity prices with respect to our POP processing agreements, and the differential between the individual NGL purity products and NGLs in storage utilized by our natural gas liquids operations. To manage the risk from market fluctuations in natural gas, NGL and condensate prices, we use commodity derivative instruments such as futures contracts, swaps and options. However, we do not fully hedge against commodity price changes, and we therefore retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs.
If the level of drilling and production in the Mid-Continent, Rocky Mountain and Gulf Coast regions substantially declines, our volumes and revenues could decline.
Our ability to maintain or expand our 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 our 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 our 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, our 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 our transportation services could significantly decrease.
We depend on natural gas supply from the Western Canada Sedimentary Basin because our Interstate Natural Gas Pipelines segment primarily transports primarily Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S. market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and production remains flat or declines, demand for transportation service on our interstate natural gas pipelines could decrease significantly, which could adversely impact our 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 us to incur significant capital and operating expenditures to make repairs or take remediation, preventive or mitigating actions that are determined to be necessary.
Growing our business by constructing new pipelines and new processing and treating facilities or making modifications to our existing facilities subjects us 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 we intend to grow our business is through the construction of pipelines and modifications to our existing pipeline systems, plants and fractionators and the construction of new pipelines and new gathering, processing and treatment facilities. The construction and modification of pipelines and gathering, processing, fractionation and treatment facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. Construction projects in our industry may increase demand on labor and material which may in turn impact our costs and schedule. If we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost. Additionally, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. We may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Additionally, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our 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 our expected investment return, which could adversely affect our results of operations and financial condition.
Our regulated natural gas pipelines’ transportation rates are subject to review and possible adjustment by federal regulators.
Our regulated pipelines are subject to extensive regulation by the FERC and state regulatory agencies, which regulates most aspects of our pipeline business, including our transportation rates. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. Under Northern Border Pipeline’s 2006 rate case settlement, there is a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from
challenging Northern Border Pipeline’s rates, and a requirement that Northern Border Pipeline file a rate case within six years.
In the competition for customers, we may have significant levels of uncontracted or discounted transportation capacity on our interstate natural gas pipelines.
Our Pipelines and Storage and Interstate Natural Gas Pipelines segments compete with other pipelines for natural gas supplies delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our pipelines, which could adversely impact our results of operations.
Our interstate natural gas pipelines have recorded certain assets that may not be recoverable from our customers.
Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition 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 operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.
The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our 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 our 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 us or locations to which we have 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 our facilities.
Various governmental authorities, including the United States EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of the products we gather, transport and process, air emissions related to our operations, historical industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our 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 our operations. Some sites we operate 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 ours. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase our 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.”
Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our 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 our products and activities and federal and state agencies could impose additional safety requirements, all of which could materially affect our profitability.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our customers are predominantly natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their credit-worthiness or ability to pay us for our services. We obtain the maximum security allowed under the FERC credit-worthiness policy for our FERC-regulated assets. 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 our results of operations. In addition, if any of our customers filed for bankruptcy protection, we may not be able to recover amounts owed or resell the capacity held by such customer, which would negatively impact our results of operations.
Our use of financial instruments to hedge market risk may result in reduced income.
We utilize financial instruments to mitigate our exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce our exposure to interest rate fluctuations could expose us to risk of financial loss where we have 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 we would otherwise receive if we have 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 our exposure to commodity price fluctuations may limit the benefit we would otherwise receive if market prices for natural gas and NGLs exceed the stated price in the hedge instrument for these commodities.
Our inability to execute growth and development projects related to our interstate pipelines and acquire new assets could reduce cash distributions to unitholders.
Our interstate natural gas pipelines are generally allowed to collect a return on their assets’ recorded book value, generally referred to as rate base, in their transportation rates. Our interstate pipelines must maintain or increase the book value of their assets through growth projects in order to maintain or increase the return collected on our rate base. Accordingly, if we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations.
RISKS INHERENT IN AN INVESTMENT IN US
The issuance of Class B units to ONEOK in connection with the acquisition of the ONEOK Energy Assets diluted our current unitholders’ ownership interests.
In connection with the acquisition of the ONEOK Energy Assets, we issued approximately 36.5 million Class B limited partner units to ONEOK. The issuance of the Class B units decreased our common unitholders’ proportionate ownership interest in us. The Class B units will be eligible to convert into common units on a one-for-one basis at the holder’s option upon the requisite approval of such conversion by our common unitholders at a special meeting of common unitholders, or automatically upon the requisite approval of both the conversion and certain amendments to our Partnership Agreement by our common unitholders at a special meeting of common unitholders which is scheduled for March 29, 2007.
In addition, ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and price that we deem appropriate.
We do not operate all of our assets nor do we directly employ any of the persons responsible for providing us with administrative, operating and management services. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
We rely on ONEOK, ONEOK Services Company and ONEOK Partners GP to provide us with administrative, operating and management services. We have a limited ability to control our operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. ONEOK, ONEOK Services Company and ONEOK Partners GP may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should ONEOK, ONEOK Services Company and ONEOK Partners GP not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services
in a timely manner, which may impact our ability to perform under our contracts and negatively affect our business and operating results. Our reliance on ONEOK, ONEOK Services Company, and ONEOK Partners GP and the third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.
The composition of natural gas received by our pipelines could reduce our available transportation capacity and increase our operating expenses.
If the energy content of the natural gas received by our pipelines is below the energy equivalent specified under our transportation contracts, we must transport additional natural gas to meet our contractual commitments. The transportation of this additional natural gas reduces the available transportation capacity on our pipelines and could negatively impact our operating revenue.
The Board of Directors of our general partner, our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.
ONEOK owns 100 percent of our general partner interest and a 43.7 percent limited partner interest in us. Although ONEOK, through the Board of Directors of our general partner, has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the Board of Directors of ONEOK has a fiduciary duty to manage our general partner in a manner beneficial to ONEOK. Two members of the Board of Directors of our general partner are also members of ONEOK’s Board of Directors. Conflicts of interest may arise between our general partner and its affiliates and us and our unitholders. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders as long as it does not take action that conflicts with our Partnership Agreement or its limited fiduciary duties. These conflicts include, among others, the following situations:
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our general partner, which is owned by ONEOK, and the Board of Directors of our general partner are allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting their fiduciary duties to our unitholders;
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our Partnership Agreement limits the liability and reduces the fiduciary duties of the members of the Board of Directors of our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
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the Board of Directors of our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
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the Board of Directors of our general partner approves the amount and timing of any capital expenditures and determines whether they are maintenance capital expenditures or growth capital expenditures, which can affect the amount of cash that is distributed to our unitholders;
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the Board of Directors of our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
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the Board of Directors of our general partner and its Audit Committee determine which costs incurred by the Board of Directors, our general partner and its affiliates are reimbursable by us;
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our Partnership Agreement does not restrict the members of the Board of Directors of our general partner from causing us to pay the Board of Directors, our general partner or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of the common units; and
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the Board of Directors of our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner and its affiliates may compete directly with us and have no obligation to present business opportunities to us.
ONEOK and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us.
Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination (through its Board of Directors) whether or not to consent to any merger or consolidation of us;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in “good faith”, meaning it believed the decision was in our best interests;
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provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;
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provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Audit Committee and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in “good faith”, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
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provides that our general partner and its affiliates, officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions so long as such person acted in “good faith” and in a manner believed to be in, or not opposed to, the best interest of us and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful.
By purchasing a common unit, a common unitholder will be bound by the provisions in our Partnership Agreement, including the provisions discussed above.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of our general partner from transferring its interest to a third party. The new members or unitholders, as the case may be, of our general partner would then be in a position to replace the directors of our general partner with their own choices and to control the decisions made by the Board of Directors of our general partner.
Any reduction in our credit ratings could materially and adversely affect our business, financial condition, liquidity and results of operations.
Our senior unsecured debt has been assigned a rating by Moody’s of “Baa2” (Stable), by S&P of “BBB” (Stable) and by Fitch of “BBB” (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 Moody’s and S&P 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. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.
Increases in interest rates may cause the market price of our common units to decline.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
A downgrade of our credit rating may require us to offer to repurchase certain of our senior notes or may impair our ability to access capital.
We could be required to offer to repurchase certain of our senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s and S&P rate those senior notes below investment grade (Baa3 for Moody’s and BBB- for S&P). Further, the indenture governing our 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 our senior notes due 2012, 2016 and 2036 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 and 2036 to declare those notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repayments and repurchases. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.
We may not be able to successfully transfer operations from Omaha to Tulsa or successfully transfer the operations of Northern Border Pipeline to an affiliate of TransCanada.
The transfer of Northern Border Pipeline’s operations to an affiliate of TransCanada and the transfer of the operations of our other three interstate pipelines and our other gathering and processing activities to Tulsa is and will continue to be a complex and time-consuming process. Failure to successfully transfer the operations of Northern Border Pipeline may have a material adverse effect on Northern Border Pipeline’s business and results of operations and, consequently, our results of operations. Failure to successfully transfer the operations of our other three interstate pipelines and our other gathering and processing activities may also have a material adverse effect on our results of operations.
Our indebtedness could impair our financial condition and our ability to fulfill our debt obligations.
As of December 31, 2006, we had total indebtedness of approximately $2.0 billion. Our indebtedness could have important consequences. For example, it could:
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make it more difficult for us to satisfy our obligations with respect to our notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our notes;
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impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
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diminish our ability to withstand a downturn in our business or the economy;
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require us to dedicate a substantial portion of our cash flow from operations to debt service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, distributions to partners, general corporate purposes or other purposes;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
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place us at a competitive disadvantage compared with our competitors that have proportionately less debt.
If we are unable to meet our debt service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our notes and other indebtedness.
We and the Intermediate Partnership have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We and the Intermediate Partnership are holding companies, and our subsidiaries conduct all of our operations and own all of our operating assets. Neither we nor the Intermediate Partnership have significant assets other than the partnership interests and the equity in our subsidiaries and Northern Border Pipeline. As a result, our ability to make quarterly distributions and required payments on our indebtedness depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities, applicable state partnership laws, and other laws and regulations. If we are unable to obtain the funds necessary to make quarterly distributions or required payments on our indebtedness, we may be required to adopt one or more alternatives, such
as refinancing the indebtedness or seeking alternative financing sources to fund the quarterly distributions and indebtedness payments.
We may issue additional common units without unitholder approval, which would dilute unitholders’ ownership interests.
Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units, subject to the limitations imposed by the NYSE. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the distribution paid on each unit may decrease;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon the sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our Partnership Agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.
Our Partnership Agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Our Partnership Agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, cannot vote on any matter. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.
Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business. Unitholders may also have liability to repay distributions.
As a limited partner in a limited partnership organized under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if they participate in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. In addition, the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business.
TAX RISKS
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to entity level taxation by any state. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and we likely would pay state taxes as well. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our common unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity level federal taxation. In addition, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, we will be subject to a new entity level tax on the portion of our income generated in Texas beginning in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7 percent of our gross income apportioned to Texas. Imposition of such tax on us by Texas, or any other state, will reduce the cash available for distribution to our common unitholders.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and general partner.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the federal income tax positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may adversely impact the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, the proceeding may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
A unitholder may be required to pay taxes on a share of our income even if the unitholder does not receive any cash distributions from us.
A unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, whether or not the unitholder receives cash distributions from us. A unitholder may not receive cash distributions from us equal to the unitholder’s share of our taxable income or even equal to the actual tax liability that result from their share of our taxable income.
The taxable gain or loss on the disposition of our common units could be different than expected.
A unitholder will recognize a gain or loss on the sale of common units equal to the difference between the amount realized and the unitholder’s tax basis in those common units. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received plus the unitholder’s share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale. Prior distributions to a unitholder in excess of the total net taxable income allocated to a unitholder for a common unit, which decreased the tax basis in that common unit, will, in effect, become taxable income to a unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing a gain, may be ordinary income to a unitholder.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, regulated investment companies known as mutual funds, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons may be subject to U.S. withholding taxes. Non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.
Unitholders will be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to federal income taxes, unitholders will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all United States federal, state and local tax returns and foreign tax returns, as applicable.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve the non-resident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our units.
The sale or exchange of 50 percent or more of the total interest in our capital and profits within a 12-month period will result in the termination of our Partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not Applicable.
ITEM 2.
ITEM 2. PROPERTIES
Gathering and Processing
Our gathering and processing assets gather natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas. In addition, we gather natural gas in three producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana, North Dakota, and the Canadian province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming.
In the Mid-Continent and Rocky Mountain regions, raw natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and NGLs are extracted. In some cases, the NGLs are separated into marketable components, including ethane, propane, iso-butane, normal butane and natural gasoline, utilizing a distillation process known as fractionation and the components are sold to refineries or local markets. The remaining residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to the end user.
Our Gathering and Processing segment assets consist of the following:
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approximately 10,100 miles and 4,500 miles of gathering pipelines with capacity owned, leased or contracted for in the Mid-Continent and Rocky Mountain regions, respectively;
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10 active processing plants, with approximately 1.6 Bcf/d of owned, leased or contracted processing capacity in the Mid-Continent region, and four active processing plants with approximately 80 MMcf/d of owned, leased or contracted processing capacity in the Rocky Mountain region; and
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approximately 89 MBbl/d and 11 MBbl/d of owned, leased or contracted natural gas liquids fractionation capacity in the Mid-Continent and Rocky Mountain regions, respectively.
Our natural gas processing operations utilize straddle and field gas processing plants to extract NGLs from raw natural gas and remove water vapor and other contaminants from the raw natural gas stream. A straddle gas processing plant is situated on a pipeline system and relies on the pipeline’s natural gas throughput volume, which subjects the plant to increased supply risk as it is dependent upon the throughput of a single pipeline rather than several supply sources. Field gas processing plants gather raw natural gas from multiple producing wells.
On January 1, 2007, the Bushton Plant was temporarily idled. Volumes available for processing at this straddle plant have declined due to contract terminations and natural field declines which made it more efficient to process the remaining gas at other facilities. We have contracted for all of the capacity of the plant from ONEOK. We are in the process of adding new facilities and making other changes at the plant as part of our Overland Pass Pipeline Company project. The plant currently has 1.0 Bcf/d processing capacity and 80 MBbl/d fractionation capacity.
Natural Gas Liquids
The natural gas liquids assets we acquired from ONEOK consist of facilities that gather, fractionate and treat NGLs and store NGL purity products primarily in Oklahoma, Kansas and Texas, as well as storage facilities and an 80 percent interest in fractionation facilities located in Mont Belvieu, Texas. Approximately 90 percent of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from raw natural gas, are connected to the gathering systems that we acquired, although some are also connected to alternative gathering systems. The natural gas liquids operations gather these NGLs and deliver them to our fractionators. The NGLs are then separated into marketable components, including ethane/propane mix, propane, iso-butane, normal butane and natural gasoline, through a fractionation process, to realize the greater economic value of the NGL components. The individual NGL components are then stored or distributed to petrochemical manufacturers, refineries and propane distributors. The fractionation and storage facilities we acquired are connected to the key natural gas liquids market centers in Conway, Kansas and Mont Belvieu, Texas by FERC-regulated interstate natural gas liquids pipelines, which are part of the pipelines and storage assets we acquired.
Our Natural Gas Liquids segment assets consist of the following:
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approximately 1,950 miles of natural gas liquids gathering pipelines;
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approximately 160 miles of natural gas liquids distribution pipelines;
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interests in four natural gas liquids fractionators with proportional operating capacity of approximately 379 MBbl/d;
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one 9 MBbl/d isomerization unit; and
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seven owned or leased storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 24.6 million Bbl.
Pipelines and Storage
The pipeline and storage assets we acquired from ONEOK gather and transport natural gas through regulated intrastate natural gas transmission pipelines and NGLs through FERC-regulated natural gas liquids gathering and distribution pipelines and operate non-processable natural gas gathering and storage facilities in Oklahoma, Kansas and Texas.
Our intrastate pipelines in Oklahoma access major natural gas producing areas and transport natural gas and NGLs throughout the state. In Texas, our intrastate 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. We also have intrastate pipelines that access the major natural gas producing area in south central Kansas.
We operate approximately 2,400 miles of FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas. Our regulated natural gas liquids pipelines deliver NGLs gathered from natural gas processing plants located in Oklahoma, Kansas and the Texas panhandle to fractionation facilities in Medford, Oklahoma, Hutchinson and Conway, Kansas, and Mont Belvieu, Texas. Our natural gas liquids distribution pipelines move products from Oklahoma and Kansas to the market centers of Conway, Kansas and Mont Belvieu, Texas.
Our Pipelines and Storage segment assets consist of the following:
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approximately 5,700 miles of intrastate natural gas gathering and regulated intrastate transmission pipelines with peak transportation capacity of approximately 2.9 Bcf/d;
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approximately 2,400 miles of FERC-regulated natural gas liquids gathering and distribution pipelines with peak transportation capacity of approximately 355 MBbl/d; and
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11 underground natural gas storage facilities in Oklahoma, Kansas and Texas with active working gas capacity of approximately 51.6 Bcf.
One of our natural gas storage facilities has been idle since 2001 following natural gas explosions and eruptions of natural gas geysers in Hutchinson, Kansas. Since that time, the Kansas Department of Health and Environment (KDHE) issued regulations related to storage activity not only at our facility, but throughout Kansas. We will begin injecting brine into the facility in the first quarter of 2007 in order to ensure the long-term integrity of the facility until its future use is determined. We are currently operating under the permit requirements filed with the KDHE that allow us to monitor the field while we complete the engineering, geological and economic studies necessary to determine the steps required to return the field to economical service and be in compliance with the new regulations.
Interstate Natural Gas Pipelines
Our interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas pipelines in Montana, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission, OkTex Pipeline and a 50 percent interest in Northern Border Pipeline.
Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee and several interstate pipelines near Joliet, Illinois. Viking Gas Transmission transports natural gas from an interconnection with TransCanada near Emerson, Manitoba to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin. Guardian Pipeline interconnects with several pipelines in Joliet, Illinois and with a local distribution company in Ixonia, Wisconsin. OkTex Pipeline has interconnects in Oklahoma, New Mexico and Texas and was acquired as part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments.”
These assets consist of the following:
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approximately 1,270 miles of interstate natural gas pipelines;
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approximately 16 compressor stations with approximately 160,000 horsepower;
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approximately 2.0 Bcf/d of peak transportation capacity; and
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50 percent interest in Northern Border Pipeline.
Other
Our Other segment consists of Black Mesa which is a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005. On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired and our coal slurry pipeline operations were shut down as expected.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Notice of Rate Change of Northern Border Pipeline Company, Federal Energy Regulatory Commission, Docket No. RP06-72-000. On November 1, 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of a settlement reached by Northern Border Pipeline in its 1999 rate case. The rate case filing proposed a 7.8 percent increase to Northern Border Pipeline’s revenue requirement; a change to its rate design approach with a supply zone and market area utilizing a fixed rate per dekatherm and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily to recover costs related to powering electric compressors; and the implementation of a short-term rate structure on a prospective basis. In December 2005, the FERC issued an order that identified issues raised in the proceeding and accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates were to be collected subject to refund until final resolution of the rate case. On September 18, 2006, Northern Border Pipeline filed a stipulation
and agreement pursuant to the settlement reached between Northern Border Pipeline and its participant customers. The settlement, supported by the FERC trial staff, established maximum long-term mileage-based rates and charges for transportation on the Northern Border Pipeline system. Beginning in 2007, overall rates were reduced, compared with rates prior to the filing, by approximately 5 percent. For the full transportation path from Port of Morgan, Montana, to the Chicago area, the previous charge of approximately $0.46 per dekatherm is now approximately $0.44 per dekatherm, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant increased from 2.25 percent to 2.40 percent. The settlement also provided for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per dekatherm to approximately $0.29 per dekatherm for the full transportation route from Port of Morgan, Montana to the Chicago area. The settlement included a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging these rates, and requires that Northern Border Pipeline file a rate case within six years. The non-contested settlement was certified on October 20, 2006, by the administrative law judge presiding over the case and approved by FERC on November 21, 2006. Refunds were paid during the fourth quarter of 2006.
Richard Manson v. Northern Plains Natural Gas Company, LLC, et. al., Civil Action No. 1973-N, in the Court of Chancery of the State of Delaware in and for New Castle County. On March 2, 2006, a holder of limited partnership units of Northern Border Partners, L.P. (“Northern Border”), now known as ONEOK Partners, L.P., filed a class action and derivative complaint on behalf of a putative class of all holders of Northern Border limited partnership units against Northern Border, TransCanada Corporation, ONEOK, Inc. and some of its affiliates, and the individual members of the Policy Committee of Northern Border. The plaintiff claimed that the transactions announced on February 15, 2006, including the sale of the ONEOK Energy Assets to Northern Border, an increase of ONEOK’s general partner interest in Northern Border to 100 percent and the sale by Northern Border of 20 percent of its interest in Northern Border Pipeline to TC PipeLines, LP, constituted a breach of Northern Border’s Partnership Agreement and a breach of defendants’ fiduciary duties. On December 1, 2006, a Stipulation of Settlement was filed with the Court. The principal terms of the settlement are: (1) a reduction in the distribution premium on ONEOK-owned units from 115 percent to 110 percent if the vote on the unit conversion and partnership amendment fail; (2) a reduction of the distribution premium on ONEOK-owned units from 125 percent to 123.5 percent if the vote on the unit conversions and partnership amendment fail and ONEOK or its subsidiary is later removed as general partner; and (3) the defendants would not object to an attorney fee award of $2,500,000 or less and expenses of not more than $50,000. Notice of the settlement was mailed to the common unitholders of ONEOK Partners, L.P. on December 4, 2006. The fairness hearing on the settlement was held on January 18, 2007, and the Chancery Court entered an Order and Final Judgment approving the settlement and awarding plaintiff’s attorneys a $2,500,000 fee and up to $50,000 in costs. Our share of the attorneys’ fees and costs is $375,000.
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 Mid-Continent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), as well as approximately 225 other defendants. 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 Mid-Continent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. 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.
Praxair, Inc. v. ONEOK Field Services Company, et al., District Court of Ellsworth County, Kansas, Case No. 04-C-17. Plaintiff alleges that ONEOK Field Services Company and ONEOK Bushton Processing, Inc. wrongfully declared force majeure under their agreement with plaintiff for delivery of helium. Plaintiff’s initial petition filed in March 2004 claimed damages for breach of contract and breach of good faith and fair dealing in excess of $20 million. Plaintiff increased its
damage claim in March 2006 and now seeks to recover $41.5 million in breach of contract damages for the failure to deliver helium. The trial is currently scheduled for March 2007.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
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 equity consists of a 2 percent general partner interest and a 98 percent limited partner interest. Our limited partner interests are represented by our common units, which are listed on the NYSE under the trading symbol “OKS,” and our Class B limited partner units, which will be convertible into common units upon the approval of the majority of our common unitholders. The following table sets forth the high and low closing prices of our common units for the periods indicated.
At February 1, 2007, there were approximately 67,242 beneficial owners (held in street name) and 1,020 holders of record of our 46,397,214 outstanding common units.
CASH DISTRIBUTIONS
The following table sets forth the quarterly cash distribution declared and paid on our common and Class B units during the periods indicated.
In January 2007, we increased our cash distribution to $0.98 per unit for the fourth quarter of 2006, which was paid on February 14, 2007, to unitholders of record as of January 31, 2007.
CASH DISTRIBUTION POLICY
Under our Partnership Agreement, we make distributions to our partners with respect to each calendar quarter in an amount equal to 100 percent of available cash within 45 days following the end of each quarter. Available cash generally consists of our cash receipts adjusted for our cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to our general partner. As an incentive, our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, our general partner receives:
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15 percent of amounts distributed in excess of $0.605 per unit,
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25 percent of amounts distributed in excess of $0.715 per unit and
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50 percent of amounts distributed in excess of $0.935 per unit.
We paid cash distributions to our general and limited partners of $265.5 million for 2006 and $159.6 million for 2005 which included an incentive distribution to our general partner of $31.6 million for 2006 and $8.0 million with respect to 2005.
Additional information about our cash distributions is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Liquidity and Capital Resources,” and Item 13, Certain Relationships and Related Transactions, and Director Independence.
ISSUANCE OF CLASS B UNITS
In April 2006, we issued approximately 36.5 million Class B units to ONEOK as part of the acquisition of the ONEOK Energy Assets. See the discussion of the ONEOK Energy Assets acquisition in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Recent Developments.” The Class B units are currently subordinated to the common units with respect to the payment of the minimum quarterly distributions, which are $0.55 per unit, and thereafter, the holders of the Class B units have the same right to receive minimum quarterly distributions as those received by the holders of the common units. If distributions to all unitholders exceed $0.55 per unit, the holders of common units and the holders of Class B units receive the same distribution per unit. The Class B units have limited voting rights. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of the Contribution Agreement between ONEOK and us on February 14, 2006. The Class B limited partner units were issued on April 6, 2006.
We will hold a special election for holders of common units on March 29, 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to our Partnership Agreement. The proposed amendments to our Partnership Agreement would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the conversion and the amendments are approved by the common unitholders, the Class B units will automatically convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the Class B unit distribution would increase to 110 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and amendments, the amount payable on such Class B units would increase to 123.5 percent of the distributions payable with respect to the common units, and 125 percent of the distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated to the common units with respect to the minimum quarterly distributions unless and until the conversion described above has been approved. The Class B units were not registered in reliance on the exemption from registration with the SEC as set forth in Section 4(2) of the Securities Act of 1933, as amended, as a transaction not involving any public offering.
PERFORMANCE GRAPH
The following performance graph compares the performance of our common units with the S&P 500 Index and the S&P Utilities Index during the period beginning on December 31, 2001 and ending on December 31, 2006. The graph assumes a $100 investment in our common units and in each of the indices at the beginning of the period and a reinvestment of distributions/dividends paid on such investments throughout the period.
Value of $100 Investment Assuming Reinvestment of Distributions/Dividends
At December 31, 2001, and at the End of Every Year Through December 31, 2006
Among ONEOK Partners, L.P., The S&P 500 Index and The S&P Utilities Index
(a) The S&P Utilities Index is comprised of the following: AES Corp.; Allegheny Energy, Inc.; Ameren Corp.; American Electric Power; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Constellation Energy Group; Dominion Resources Inc.; DTE Energy Co.; Duke Energy Corp.; Dynegy, Inc.; Edison Int’l.; Entergy Corp.; Exelen Corp.; FirstEnergy Corp.; FPL Group, Inc.; KeySpan Corp.; Nicor, Inc.; NiSource, Inc.; Peoples Energy Corp.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress Energy, Inc.; Public Service Enterprise Group; Questar Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; TXU Corp.; and Xcel Energy, Inc.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the periods indicated.
Financial data for 2006 is not directly comparable to prior years due to the significance of the April 2006 ONEOK Transactions. See discussion of acquisitions, dispositions and changes in consolidation beginning on page 32 under “Recent Developments” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
EXECUTIVE SUMMARY
The following discussion highlights some of our achievements and significant issues affecting us this past year. Please refer to the Financial and Operating Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Financial Statements for a complete explanation of the following items.
Net income from continuing operations per unit increased to $5.01 in 2006, which includes a $1.51 per unit gain on sale of assets from the sale of our 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. Net income from continuing operations per unit was $2.92 in 2005 and $2.81 in 2004.
On January 16, 2007, we declared a cash distribution of $0.98 per unit ($3.92 per unit on an annualized basis) for the fourth quarter of 2006. The distribution was paid on February 14, 2007, to unitholders of record on January 31, 2007.
Operating income for 2006 was $510.6 million, an increase of $253.8 million, or 99 percent, from 2005. The increase in operating income excluding the gain on sale of assets was $139.0 million, or 54 percent. The gain on sale of assets primarily relates to our sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006.
The April 2006 acquisition of the ONEOK Energy Assets, which were consolidated as of January 1, 2006 for financial reporting purposes, resulted in $321.4 million in additional operating income for 2006. The deconsolidation of Northern Border Pipeline as of January 1, 2006 resulted in a reduction in operating income of $192.7 million for the year.
In September 2006, we completed an underwritten public offering of $1.4 billion in senior notes. The net proceeds from these senior notes of approximately $1.39 billion, after deducting underwriting discounts, commissions and expenses but before offering expenses, were used to repay all of the $1.05 billion outstanding under our $1.1 billion, 364-day credit agreement (the Bridge Facility), and to repay $335 million of indebtedness outstanding under our five-year $750 million amended and restated revolving credit agreement (the 2006 Partnership Credit Agreement).
RECENT DEVELOPMENTS
Increased Cash Distributions - The following increases were made to our quarterly cash distribution since January 1, 2006.
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In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006, which was paid on May 15, 2006, to unitholders of record as of April 28, 2006.
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In July 2006, we increased our cash distribution to $0.95 per unit for the second quarter of 2006, which was paid on August 14, 2006, to unitholders of record as of July 31, 2006.
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In October 2006, we increased our cash distribution to $0.97 per unit for the third quarter of 2006, which was paid on November 14, 2006, to unitholders of record as of October 31, 2006.
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In January 2007, we increased our cash distribution to $0.98 per unit for the fourth quarter of 2006, which was paid on February 14, 2007, to unitholders of record as of January 31, 2007.
ONEOK Transactions - In April 2006, we completed the acquisition of the ONEOK Energy Assets through the ONEOK Transactions, described below.
Acquisition of ONEOK Energy Assets - We acquired certain companies comprising ONEOK’s former gathering and processing, natural gas liquids, and pipelines and storage segments for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units which, when combined with its general partner interest, increased its total interest in us to approximately 45.7 percent. We also used $1.05 billion drawn under our Bridge Facility, coupled with the proceeds from the sale of a 20 percent partnership interest in Northern Border Pipeline, to finance the transaction. The assets were recorded at historical cost rather than at fair value since these transactions were between affiliates under common control. These assets and their related operations are included in our consolidated financial statements as of January 1, 2006.
Under the terms of the ONEOK Transactions, we recorded a $72.6 million purchase price adjustment related to the finalized working capital settlement. The working capital settlement is reflected as an increase to the value of the Class B units and was approved by our Audit Committee.
Our Audit Committee, which consisted solely of three independent members, determined that the ONEOK Transactions were fair and reasonable to us and in the interests of our public unitholders. As provided for in our Partnership Agreement, the Audit Committee engaged independent legal counsel and an independent financial adviser to assist in its determination.
Equity Issuance - In connection with the ONEOK Transactions, we amended our Partnership Agreement to provide for the issuance of Class B limited partner units and issued approximately 36.5 million Class B limited partner units to ONEOK. The Class B units are currently subordinated to the common units with respect to the payment of the minimum quarterly distributions, which are $0.55 per unit, and thereafter, the holders of the Class B units have the same right to receive minimum quarterly distributions as to those received by the holders of the common units. If distributions to all unitholders exceed $0.55 per unit, the holders of common units and the holders of Class B units receive the same distribution per unit. The Class B units have limited voting rights. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of the Contribution Agreement between ONEOK and us on February 14, 2006. The Class B limited partner units were issued on April 6, 2006.
We will hold a special election for holders of common units on March 29, 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to our Partnership Agreement. The proposed amendments to our Partnership Agreement would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the conversion and the amendments are approved by the common unitholders, the Class B units will automatically convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the Class B unit distribution would increase to 110 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and amendments, the amount payable on such Class B units would increase to 123.5 percent of the distributions payable with respect to the common units, and 125 percent of the distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated to the common units with respect to the minimum quarterly distributions unless and until the conversion described above has been approved.
Purchase and Sale of General Partner Interest - In April 2006, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. As a result, ONEOK now owns our entire 2 percent general partner interest and controls us.
Disposition of 20 Percent Partnership Interest in Northern Border Pipeline - In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline and an affiliate of TransCanada will become the operator of the pipeline in April 2007. As a result of the transaction, Northern Border Pipeline
is no longer consolidated in our financial statements. Instead, our interest in Northern Border Pipeline is accounted for as an investment under the equity method effective January 1, 2006.
In addition, the General Partnership Agreement for Northern Border Pipeline was amended and restated, effective April 6, 2006. The major provisions adopted or changed include the following:
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the Management Committee of Northern Border Pipeline consists of four members. Each partner designates two members and TC PipeLines designates one of its members as chairman;
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the Management Committee designates the members of the Audit Committee, which consists of three members. One member is selected by members of the Management Committee designated by the partner whose affiliate is the operator and two members are selected by the members of the Management Committee designated by the other partner; and
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ONEOK Partners GP will operate Northern Border Pipeline until April 1, 2007. Effective April 1, 2007, an affiliate of TransCanada will become the operator.
Our Audit Committee determined that the disposition of the 20 percent interest in Northern Border Pipeline was fair and reasonable to us and in the interests of our public unitholders. As provided for in our Partnership Agreement, the Audit Committee engaged independent legal counsel and an independent financial adviser to assist in its determination.
Services Agreement - In April 2006, we entered into a Services Agreement with ONEOK, ONEOK Partners GP and NBP Services that replaced the Administrative Services Agreement between us and NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK will provide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP will continue to operate our interstate natural gas pipelines assets according to each pipeline’s operating agreement, except for the operating agreement between ONEOK Partners GP and Northern Border Pipeline, which will terminate effective April 1, 2007. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its responsibilities.
Acquisition of Guardian Pipeline Interests - In April 2006, we acquired the 66 2/3 percent interest in Guardian Pipeline not previously owned by us for approximately $77 million, increasing our ownership to 100 percent. We used borrowings from our credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Guardian Pipeline is consolidated in our consolidated financial statements and reported in our Interstate Natural Gas Pipelines segment as of January 1, 2006. Prior to the transaction, our 33 1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.
Reorganization Agreement - On September 15, 2006, we entered into a Reorganization Agreement with the Intermediate Partnership, ONEOK Partners GP, our general partner, and the ILP GP. The Reorganization Agreement was entered into so that the Intermediate Partnership, as a 100 percent owned subsidiary, would not be subject to SEC reporting requirements and could therefore avoid the administrative burden and costs associated with being a reporting entity. Pursuant to the Reorganization Agreement, the equity ownership structure of the Intermediate Partnership was reorganized so that we became the 100 percent owner of the Intermediate Partnership and the ILP GP became its sole general partner. Subsequent to the formation of the ILP GP:
(i) we contributed a 0.01 percent limited partner interest in the Intermediate Partnership to the ILP GP in exchange for all the membership interests in the ILP GP;
(ii) the 0.01 percent limited partner interest in the Intermediate Partnership held by the ILP GP was converted into a 0.01 percent general partner interest in the Intermediate Partnership;
(iii) the 1.0101 percent general partner interest in the Intermediate Partnership held by our general partner was converted into a 1.0101 percent limited partner interest in the Intermediate Partnership; and
(iv) our general partner contributed to us its 1.0101 percent limited partner interest in the Intermediate Partnership in exchange for an increase in its general partner percentage interest in us from 1 percent to 2 percent.
Amendments to our Partnership Agreement - Effective September 15, 2006, our general partner entered into the Partnership Agreement to amend and restate our previously existing partnership agreement. Among other things, our existing partnership agreement was revised to:
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reflect that the general partner now owns a 2 percent general partner interest in us, whereas it previously owned a combined 2 percent general partner interest in us and the Intermediate Partnership;
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correct certain cross references and typographical errors made in the previously existing partnership agreement; and
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delete certain unused definitions and add new defined terms related to the transactions contemplated under the Reorganization Agreement.
In May 2006, our general partner entered into the Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. to amend and restate our previously existing partnership agreement. The Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P.:
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changed the name of Northern Border Partners, L.P. to ONEOK Partners, L.P.;
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provided that we are managed by our sole general partner, ONEOK Partners GP;
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replaced our previously existing Partnership Policy Committee and Audit Committee with the Board of Directors and Audit Committee of ONEOK Partners GP; and
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separated the functions of the Audit Committee, which will be a standing committee of the Board of Directors of ONEOK Partners GP, which will not be a standing committee of the Board of Directors of ONEOK Partners GP.
Amendment to the ONEOK Partners Intermediate Partnership Amended and Restated Partnership Agreement - Effective September 15, 2006, the ILP GP, as the successor general partner of the Intermediate Partnership, entered into Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of the Intermediate Partnership (Amendment No. 1). Among other things, Amendment No. 1:
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changed the general partner of the Intermediate Partnership from ONEOK Partners GP to the ILP GP;
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converted the percentage interest held by our general partner from a 1.0101 percent general partner interest to a 1.0101 percent limited partner interest; and
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revised and added certain provisions and definitions related to the transactions contemplated under the Reorganization Agreement.
Name Change - In May 2006, we filed a Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. to change our name to ONEOK Partners, L.P. Northern Border Intermediate Limited Partnership also filed a Certificate of Amendment to Certificate of Limited Partnership of Northern Border Intermediate Limited Partnership to change its name to ONEOK Partners Intermediate Limited Partnership.
Change of Directors and Officers - In May 2006, we amended and restated our Partnership Agreement to replace our Partnership Policy Committee and Audit Committee with the Board of Directors and Audit Committee of our sole general partner, ONEOK Partners GP. As a result, all of our officers and the members of the Partnership Policy Committee resigned and ONEOK Partners GP elected a six-member Board of Directors, three of whom are independent and also serve on the Audit Committee of the Board of Directors of ONEOK Partners GP.
Debt Issuance - In September 2006, we 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). We 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. See “Liquidity and Capital Resources - Financing” for more information regarding the Notes.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts, commissions and expenses but before offering expenses, were used to repay all of the $1.05 billion outstanding under our Bridge Facility and to repay $335 million of indebtedness outstanding under our 2006 Partnership Credit Agreement.
Settlement of Rate Case - In September 2006, Northern Border Pipeline filed a stipulation and agreement that documented the settlement reached between Northern Border Pipeline and its participant customers and supported by the FERC trial staff. The uncontested settlement was certified in October 2006, by the administrative law judge and approved by the FERC in November 2006. Based on the settlement, Northern Border Pipeline refunded $10.8 million to its customers in the fourth quarter of 2006.
The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border Pipeline’s system. Beginning in 2007, overall rates were reduced, compared with rates prior to the filing, by approximately 5 percent. For the full transportation route from Port of Morgan, Montana, to the Chicago area, the previous charge of approximately $0.46 per Dth is now approximately $0.44 per Dth, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant were increased from 2.25 percent to 2.40 percent. The settlement also provided for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth to approximately $0.29 per Dth for the
full transportation route from Port of Morgan, Montana, to the Chicago area. The settlement included a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging these rates, and requires that Northern Border Pipeline file a rate case within six years.
Capital Projects
Northern Border Pipeline Chicago III Expansion Project - In April 2006, the Chicago III Expansion Project went into service as planned, adding approximately 130 MMcf/d of transportation capacity on the eastern portion of Northern Border Pipeline into the Chicago area.
Overland Pass Pipeline Company - In May 2006, we entered into an agreement with a subsidiary Williams to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company will build a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. As the 99 percent owner of the joint venture, we 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 us for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer of 2007, with start up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million excluding AFUDC. During 2006, we paid $11.6 million to Williams for acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. In addition, we plan to invest approximately $216 million excluding AFUDC to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and federal regulatory authorities.
Texarkoma Pipeline Proposal - In June 2006, we signed a non-binding letter of intent to form a joint venture with Boardwalk Pipeline Partners, LP and Energy Transfer Partners, LP to construct a new interstate natural gas pipeline originating in north Texas, crossing Oklahoma and Arkansas and terminating in Coahoma, Mississippi, at a new interconnect with Texas Gas Transmission, L.L.C. The proposed interstate pipeline would have created new pipeline capacity for constrained wellhead production in north Texas and central Oklahoma and would have initial capacity of up to 1.0 Bcf/d. In August 2006, Energy Transfer Partners, LP withdrew from the joint venture. In January 2007, we withdrew from the letter of intent, but we continue to work with Boardwalk Pipeline Partners, LP and others to determine the feasibility of a project to deliver incremental natural gas volumes to Texas Gas Transmission, L.L.C. Any transaction is still subject to negotiation and execution of definitive agreements.
Guardian Pipeline Expansion and Extension Project - In October 2006, Guardian Pipeline filed its application for a certificate of public convenience and necessity with the FERC for authorization to construct and operate approximately 110 miles of new mainline pipe, two compressor stations, seven meter stations and other associated facilities. The pipeline expansion will extend Guardian Pipeline from the Milwaukee, Wisconsin area to the Green Bay, Wisconsin area. The project is supported by long-term shipper commitments. The cost of the project is estimated to be $241 million excluding AFUDC, with a targeted in-service date of November 2008.
Midwestern Gas Transmission Eastern Extension Project - In March 2006, Midwestern Gas Transmission accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. An organization which is opposed to, and includes landowners affected by, the project filed a request for rehearing and for a stay of the March 2006 Order. In August 2006, the FERC denied those requests. The Eastern Extension Project will add 31 miles of pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity with total capital expenditures estimated to be $35 million, excluding AFUDC. The proposed in-service date is the fourth quarter of 2007.
Fort Union Gas Gathering Expansion Project - In January 2007, Crestone Powder River announced that Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines and 649 MMcf/d of additional capacity in the Powder River basin. The expansion is expected to cost approximately $110 million and will occur in two phases with 240 MMcf/d expected to be in service by October 2007 and 409 MMcf/d by January 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. Crestone Powder River owns approximately 37 percent of Fort Union Gas Gathering.
IMPACT OF NEW ACCOUNTING STANDARDS
In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
In September 2006, the SEC staff issued SAB Topic 1N, “Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how to quantify the effect of an error on the financial statements. SAB 108 is effective for our year ended December 31, 2006. We have completed our review of the applicability of SAB 108 to our operations and have determined that it did not have an impact on our consolidated financial statements.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are evaluating our tax positions and anticipate FIN 48 will not have a significant impact on our results of operations.
In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 was effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that it did not have a material impact on our results of operations or financial position.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty and that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.
The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
We assess our goodwill and intangible assets for impairment at least annually, based on Statement 142, “Goodwill and Other Intangible Assets.” In the third quarter of 2006, we changed our annual impairment testing date to July 1. See Note C of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion. There were no impairment charges resulting from the July 1, 2006, impairment tests and no events indicating an impairment has occurred subsequent to that date. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. At December 31, 2006, we had $394.6 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. As shown below, we had $295.2 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2006.
During 2006, we reassessed our coal slurry pipeline operation as a result of SCE’s announcement that it would no longer pursue the resumption of operations of the Mohave Generating Station. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced, and a goodwill and asset impairment of $8.4 million and $3.6 million, respectively, was recorded as depreciation and amortization. The reduction to net income after income taxes was $10.6 million. Additional information about Black Mesa is included below in this Item 7 under “Financial and Operating Results - Other.”
Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million and $185.8 million as of December 31, 2006 and 2005, respectively. These amounts were recorded in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. 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 and under Statement 142, is not subject to amortization but rather to impairment testing pursuant to APB No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with APB Opinion No. 18. See Note H in Notes to our Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of unconsolidated affiliates.
We do not currently anticipate any additional goodwill or asset impairments to occur within the next year, but if such events were to occur over the long term, the impact could be significant to our financial condition and results of operations.
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.
FINANCIAL AND OPERATING RESULTS
Consolidated Operations
Selected Financial Information - The following table sets forth certain selected financial information for the periods indicated.
Operating Results - Consolidated operating income increased for 2006, compared with 2005, primarily due to:
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the April 2006 acquisition of the ONEOK Energy Assets, consolidated effective January 1, 2006, for financial reporting purposes, which accounts for $321.4 million of our consolidated operating income;
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the $114.9 million gain on sale of assets reported in the second quarter of 2006 primarily due to the sale of a 20 percent partnership interest in Northern Border Pipeline; and
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an increase of $21.4 million due to the consolidation of Guardian Pipeline following our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us.
These increases were partially offset by:
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the goodwill and asset impairment of $12.0 million related to Black Mesa; and
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decreased operating income of $192.7 million due to the deconsolidation of Northern Border Pipeline as of January 1, 2006.
Consolidated net margin was $841.2 million in 2006, compared with $498.5 million in 2005. Net margin increased primarily due to the acquisition of the ONEOK Energy Assets, which accounts for $638.9 million of our consolidated net margin for the period, and, to a lesser extent, the effect of the Guardian Pipeline consolidation, partially offset by the effect of the Northern Border Pipeline deconsolidation.
Operating costs increased in 2006, compared with 2005, primarily due to our acquisition of the ONEOK Energy Assets.
Equity earnings from investments for 2006 primarily consisted of earnings from our interest in Northern Border Pipeline which is no longer consolidated as of January 1, 2006. Equity earnings from investments for 2005 consisted of earnings from our 33 1/3 percent interest in Guardian Pipeline, which is reflected on a consolidated basis beginning January 1, 2006.
Minority interest in net income for 2006 included earnings from the 66 2/3 percent interest in Guardian Pipeline until that interest was acquired by us in April 2006. Minority interest in net income for 2005 included earnings from the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipeline’s results were consolidated.
Operating income increased $3.4 million in 2005, compared with 2004, as a result of the significantly greater contribution by our Gathering and Processing segment, partially offset by decreased operating income from our Interstate Natural Gas Pipelines segment. Both our Interstate Natural Gas Pipelines segment and our Gathering and Processing segment benefited from the sale of their bankruptcy claims related to Enron Corp. (Enron) and Enron North America Corp. (Enron North America) in 2005.
Consolidated net margin increased $19.8 million in 2005, compared with 2004, primarily due to our Gathering and Processing segment, which had increased its net margin by $22.2 million. The increase in net margin for this segment was due to increased gathering and processing volumes in the Williston Basin and higher commodity prices realized on equity
natural gas and NGLs derived from POP contracts. An offsetting decrease was due to lower net margin for our Interstate Natural Gas Pipelines segment.
Operating costs increased $16.9 million in 2005, compared with 2004, primarily due to the settlement of several outstanding issues related to Enron which reduced operating costs in 2004.
Equity earnings from investments increased $6.7 million in 2005, compared with 2004, due to the settlement of our preferred A shares with Bighorn Gas Gathering and improved results from our gathering and processing joint-venture interests.
More information regarding our results of operations is provided in the following discussion of operating results for each of our segments.
Gathering and Processing
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Gathering and Processing segment for the periods indicated.
Operating Results - The 2005 and 2004 results for our Gathering and Processing segment do not include the assets acquired by us from ONEOK.
Our Gathering and Processing segment reported operating income of $180.2 million for 2006, compared with $44.7 million for 2005, primarily due to the acquisition of ONEOK’s gathering and processing assets.
Net margin increased $275.5 million in 2006, compared with 2005, primarily due to the following:
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the acquisition of ONEOK’s gathering and processing assets, which accounts for an increase of $263.1 million;
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an increase of $3.2 million resulting from favorable commodity pricing for natural gas and NGL products on POP contracts in the Rocky Mountain region, net of hedging; and
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an increase of $9.0 million resulting from increased natural gas volumes gathered and processed in the Rocky Mountain region, partially offset by lower average gathering rates.
The realized gross processing spread of $5.05 per MMBtu for 2006 was significantly higher than the five-year average of $2.55 per MMBtu. Based on current market conditions, the gross processing spread for 2007 is expected to be above the five-year average. We currently have 6,410 MMBtu/d of our gross processing spread hedged for 2007 at $3.06 per MMBtu.
Net margin increased $22.2 million in 2005, compared with 2004, primarily as a result of the following:
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increased gathering and processing volumes in the Williston Basin and
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higher commodity prices realized on equity natural gas and NGLs derived from POP contracts.
The weighted average realized price of natural gas, net of hedging, was $6.87 per MMBtu in 2005, compared with $4.76 per MMBtu in 2004. The weighted average realized price of NGLs, net of hedging, was $0.92 per gallon in 2005, compared with $0.53 per gallon in 2004.
Operating costs increased $4.6 million in 2005, compared with 2004, driven primarily by additional expenses related to expansions, pipeline repairs and employee costs.
Equity earnings from investments increased $6.1 million in 2005, compared with 2004. Increased volumes and transportation rates are reflected in our equity earnings along with an additional 3.7 percent interest in Fort Union Gas Gathering. We also recognized $5.4 million of equity earnings related to our preferred A shares held in Bighorn Gas Gathering that were due to us for 2004 and 2005, resulting from a settlement agreement with our partner. In 2004, we recorded $2.7 million of equity earnings related to our preferred A shares that were due to us for 2003.
Comparative Analysis of Acquired Gathering and Processing Assets - We are providing the following information for additional analysis of the gathering and processing assets we acquired from ONEOK. The ONEOK Transactions were accounted for at historical cost and therefore, the information is comparable between periods.
Net margins for the acquired assets increased $56.3 million for 2006, compared with 2005, primarily due to the following:
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an increase of $29.7 million resulting from favorable commodity pricing for natural gas and NGL products on POP contracts, net of hedging; and
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an increase of $40.2 million due to higher realized gross processing spreads on keep-whole contracts, net of hedging; partially offset by
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a decrease of $14.1 million from reduced gathered and processed volumes driven by natural reserve declines around the systems and contract terminations.
Operating costs for the acquired assets increased $8.7 million for 2006, compared with 2005, primarily due to higher legal costs and higher employee costs in 2006.
Natural Gas Liquids
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Natural Gas Liquids segment for the periods indicated.
Operating Results - We did not have a Natural Gas Liquids segment prior to 2006. Our Natural Gas Liquids segment reported operating income of $88.7 million for 2006 as a result of the acquisition of ONEOK’s natural gas liquids assets.
Comparative Analysis of Acquired Natural Gas Liquids Assets - We are providing the following information for additional analysis of the natural gas liquids assets we acquired from ONEOK. The transactions with ONEOK were accounted for at historical cost and therefore, the information is comparable between the periods. ONEOK acquired these natural gas liquids assets from Koch Industries, Inc. (Koch) in July 2005.
The following increases for 2006, compared with 2005, are primarily due to the additional six months of ownership of the natural gas liquids assets ONEOK acquired from Koch:
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an increase of $79.1 million in net margin,
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an increase of $24.1 million in operating costs, and
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an increase of $9.7 million in depreciation and amortization.
Pipelines and Storage
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Pipelines and Storage segment for the period indicated.
Operating Results - We did not have a Pipelines and Storage segment prior to 2006. Our Pipelines and Storage segment reported operating income of $107.9 million for 2006 as a result of the acquisition of ONEOK’s pipelines and storage assets.
Comparative Analysis of Acquired Pipelines and Storage Assets - We are providing the following information for additional analysis of the pipelines and storage assets we acquired from ONEOK. The transactions with ONEOK were accounted for at historical cost and therefore, the information is comparable between the periods. ONEOK acquired certain of these pipelines and storage assets from Koch in July 2005.
Net margin for the acquired assets increased $38.5 million for 2006, compared with 2005, primarily due to the following:
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an increase of $33.9 million primarily related to the additional six months of ownership of the assets ONEOK acquired from Koch;
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an increase of $6.6 million from natural gas transportation as a result of higher realized rates and higher volumes in the commodity-based short-term business and an improved fuel position; and
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a decrease of $1.9 million due to fewer equity natural gas inventory sales.
Operating costs for the acquired assets increased $9.6 million for 2006, compared with 2005, due to increased operating expense associated with the additional six months of ownership of the natural gas liquids gathering and distribution pipelines ONEOK acquired from Koch.
Interstate Natural Gas Pipelines
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Interstate Natural Gas Pipelines segment for the periods indicated.
Operating Results - Our Interstate Natural Gas Pipelines segment reported operating income of $158.5 million for 2006, compared with $214.2 million for 2005. The decrease of $55.7 million was due to a decrease of $192.7 million related to deconsolidation of Northern Border Pipeline partially offset by the $113.9 million gain on the sale of the 20 percent partnership interest in Northern Border Pipeline. Operating income also increased $21.4 million due to the acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us and $0.7 million as a result of the acquisition of OkTex Pipeline from ONEOK. Operating income also increased on our other pipelines $1.2 million due to lower depreciation expense.
Transportation revenue decreased $284.0 million due primarily to the $321.6 million decrease related to Northern Border Pipeline, which is no longer consolidated as of January 1, 2006. Our transportation revenue increased $35.4 million for 2006 due to the consolidation of Guardian Pipeline and an additional $1.7 million as a result of the acquisition of OkTex Pipeline from ONEOK.
Equity earnings from investments of $72.4 million for 2006 were primarily due to our interest in Northern Border Pipeline which is no longer consolidated as of January 1, 2006. Equity earnings from investments of $2.3 million for 2005 were primarily due to our 33 1/3 percent interest in Guardian Pipeline, which is reflected on a consolidated basis beginning January 1, 2006.
Minority interest in net income for 2006 included earnings from the 66 2/3 percent interest in Guardian Pipeline until that interest was acquired by us in April 2006. Minority interest in net income for 2005 included earnings from the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipeline’s results were consolidated.
Transportation revenue decreased $4.9 million in 2005, compared with 2004, due to Northern Border Pipeline’s decreased demand for transportation capacity. During the second quarter of 2005, contracts for 800 MMcf/d of capacity on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline expired. Some of this firm transportation capacity was not sold. To maximize revenue, Northern Border Pipeline discounted transportation rates primarily on a short-term basis and sold most of its remaining capacity in 2005. Revenue from firm service transportation decreased $16.2 million as a result of uncontracted and discounted capacity. Partially offsetting this decrease, Northern Border Pipeline recognized revenue of $9.4 million from the sale of its bankruptcy claims for transportation contracts and associated guarantees against Enron and Enron North America. In 2004, Northern Border Pipeline recognized revenue of $0.9 million due to an additional day of transportation service because of the leap year.
Operating costs increased $11.8 million in 2005, compared with 2004, primarily due to the settlement or anticipated settlement of several outstanding issues related to Enron which reduced expenses in 2004. The resolution of our potential obligation for costs related to the termination of Enron’s cash balance plan, the settlement for certain administrative expenses for 2002 and 2003, and an adjustment to our allowance for doubtful accounts related to bankruptcy claims held by Northern Border Pipeline reduced expenses by $7.2 million in 2004. In 2005, operational gas volume imbalances on Viking Gas Transmission resulted in a $2.2 million net increase in operating costs.
Equity earnings from investments for 2005 and 2004 represented earnings from our 33 1/3percent interest in Guardian Pipeline.
Regulatory Developments - In November 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its previous rate case. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding and accepted the proposed rates, but suspended their effectiveness until May 1, 2006. Beginning May 1, 2006, the new rates were collected subject to refund through September 30, 2006. Based on the settlement discussed below, the rates in effect prior to the rate case filing were collected for the months of October to December 2006, and did not result in collecting additional amounts subject to refund.
In September 2006, Northern Border Pipeline filed a stipulation and agreement that documented the settlement reached between Northern Border Pipeline and its participant customers and supported by the FERC trial staff. The uncontested settlement was certified in October 2006 by the administrative law judge and approved by the FERC in November 2006. Based on the settlement, Northern Border Pipeline refunded $10.8 million to its customers in the fourth quarter of 2006.
The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border Pipeline’s system. Beginning in 2007, overall rates were reduced, compared with rates prior to the filing, by approximately 5 percent. For the full transportation route from Port of Morgan, Montana to the Chicago area, the previous charge of approximately $0.46 per Dth is now approximately $0.44 per Dth, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant were increased from 2.25 percent to 2.40 percent. The settlement also provided for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth to approximately $0.29 per Dth for the full transportation route from Port of Morgan, Montana to the Chicago area. The settlement included a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging these rates, and requires that Northern Border Pipeline file a rate case within six years.
Other
Black Mesa consists of a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona and terminates at the Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005.
Under a consent decree, Mohave agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding ongoing water and coal supply negotiations, SCE, a 56 percent owner of Mohave, filed a petition before the California Public Utilities Commission (CPUC) requesting that they either recognize the end of Mohave’s coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.
On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired, and our coal slurry pipeline operations were shut down as expected. In June 2006, SCE completed a comprehensive study of the water source, coal supply and transportation issues, and announced that it would no longer pursue the resumption of plant operations. In February 2007, another Mohave co-owner, Salt River Project, announced it was ending its efforts to return the plant to service. Negotiations among various parties involved with Black Mesa are ongoing.
We recorded a loss on Black Mesa for 2006 of $12.0 million, which included an after-tax reduction to net income of $10.6 million for the goodwill and asset impairments recognized during the year, compared with net income in 2005 of $3.9 million. We expect that maintaining the standby status of the Black Mesa facilities will result in a loss in 2007 of approximately $3.5 million.
Legal
Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position.
LIQUIDITY AND CAPITAL RESOURCES
General - Our principal sources of liquidity include cash generated from operating activities, bank credit facilities and debt issuances. We fund our operating expenses, debt service and cash distributions to our limited and general partner primarily with operating cash flow.
Part of our growth strategy is to expand our existing businesses and strategically acquire related businesses that strengthen and complement our existing assets. Capital resources for acquisitions and maintenance and growth expenditures may be funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or sale of additional limited partner interests. Our ability to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions.
We believe that our ability to obtain financing and our history of consistent cash flow from operating activities provide a solid foundation to meet our future liquidity and capital resource requirements.
Financing - Financing is provided through available cash, the 2006 Partnership Credit Agreement and long-term debt. Other options to obtain financing include, but are not limited to, issuance of limited partner units, issuance of hybrid securities such as any trust preferred security or deferrable interest subordinated debt issued by us or any business trusts and sale/leaseback of facilities.
In addition to the short-term bridge financing agreement discussed below, the total amount of short-term borrowings authorized by our general partner’s Board of Directors is $750 million, and an additional $10 million is authorized for Guardian Pipeline. At December 31, 2006, we had $10 million in letters of credit issued, no borrowings outstanding under the 2006 Partnership Credit Agreement and available cash of approximately $21.1 million. Additionally, we had $6.0 million drawn under the $10 million Guardian Pipeline revolving credit agreement.
2006 Partnership Credit Agreement - In December 2006, we amended our 2006 Partnership Credit Agreement. This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA (net income before interest expense, income taxes and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland Pass Pipeline Company agreement from the covenant that limits our ability to enter into agreements that restrict our ability to grant liens to the lenders under the 2006 Partnership Credit Agreement.
In March 2006, we amended and restated our 2005 revolving credit agreement with certain financial institutions and increased the term for an additional five years, increased the facility to $750 million from $500 million, and lowered the pricing. The 2005 revolving credit agreement was renamed the 2006 Partnership Credit Agreement.
Under the 2006 Partnership Credit Agreement, we are required to comply with certain financial, operational and legal covenants. These requirements include:
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maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1, and
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maintaining a ratio of EBITDA to interest expense of not less than 3 to 1.
If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement may become immediately due and payable. At December 31, 2006, we were in compliance with these covenants. At December 31, 2006, a letter of credit of $10 million was outstanding under the 2006 Partnership Credit Agreement. The letter of credit expires May 1, 2007.
Bridge Facility - In April 2006, we entered into the Bridge Facility with a syndicate of banks and borrowed $1.05 billion to finance a portion of the acquisition of the ONEOK Energy Assets. In September 2006, we repaid the amounts outstanding
under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated in accordance with its terms.
Debt Issuance - In September 2006, we 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). We 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.
We 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 our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of our non-guarantor subsidiaries. The Notes are non-recourse to our general partner.
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 our Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated September 25, 2006, between us 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 our ability to place liens on our property or assets and sell and lease back our property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016, and October 1, 2036, respectively. We will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Guardian Pipeline Revolving Note - Our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us resulted in the inclusion of outstanding amounts under Guardian Pipeline’s revolving note agreement on our 2006 Consolidated Balance Sheet. The revolving note agreement permits Guardian Pipeline to choose rates based on the prime commercial lending rate or LIBOR as the interest rate on its outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and specify the interest rate period. At December 31, 2006, Guardian Pipeline had $6.0 million outstanding under its $10 million revolving note agreement at an average rate of 6.59 percent, due January 2007. The Guardian Pipeline revolving credit agreement terminates in November 2007.
Guardian Pipeline’s revolving note agreement contains typical covenants, including financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1, and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the note agreement may become due and payable immediately. At December 31, 2006, Guardian Pipeline was in compliance with its financial covenants.
Guardian Pipeline Senior Notes - Our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us resulted in the inclusion of $145.6 million of long-term debt on our 2006 Consolidated Balance Sheet. These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due quarterly through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.86 percent. Guardian Pipeline’s senior notes contain financial covenants which are substantially the same as those in Guardian Pipeline’s revolving note agreement, as described above, except that beginning in December 2007, the rate of total indebtedness to EBITDAR cannot be greater than 5.75 to 1.
Equity Issuance - In connection with the ONEOK Transactions, we amended our Partnership Agreement to provide for the issuance of Class B limited partner units and issued approximately 36.5 million Class B limited partner units to ONEOK. The Class B units are currently subordinated to the common units with respect to the payment of the minimum quarterly distributions, which are $0.55 per unit and thereafter, the holders of the Class B units have the same right to receive minimum
quarterly distributions as to those received by the holders of the common units. The Class B units have limited voting rights. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of the Contribution Agreement between ONEOK and us on February 14, 2006. The Class B limited partner units were issued on April 6, 2006.
We will hold a special election for holders of common units on March 29, 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to our Partnership Agreement. The proposed amendments to our Partnership Agreement would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the conversion and the amendments are approved by the common unitholders, the Class B units will automatically convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the Class B unit distribution would increase to 110 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and amendments, the amount payable on such Class B units would increase to 123.5 percent of the distributions payable with respect to the common units, and 125 percent of the distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated to the common units with respect to minimum quarterly distribution unless and until the conversion described above has been approved.
Capitalization Structure - The following table sets forth our capitalization structure for the periods indicated.
Credit Ratings - Our credit ratings as of December 31, 2006, are shown in the table below.
Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt to EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, the interest rates on the 2006 Partnership Agreement borrowings would increase, resulting in an increase in our cost to borrow funds.
Our $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require us to offer to repurchase the senior notes at par value if our Moody’s and S&P credit ratings fall below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade ratings are not reinstated within a period of 40 days. Further, the indentures governing our 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 our senior notes due 2012, 2016 and 2036 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016 and 2036 to declare those notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.
Capital Expenditures - As a result of the acquisition of the ONEOK Energy Assets described in this item under “Recent Developments,” our capital expenditures have increased to include growth and maintenance capital expenditures related to
the acquired assets. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Any remaining capital expenditures are classified as maintenance capital expenditures.
The following tables set forth the growth and maintenance capital expenditures for 2006, 2005 and 2004.
Growth and maintenance capital expenditures included in 2006 for ONEOK Energy Assets are $74.4 million and $46.9 million, respectively. The majority of the growth capital expenditures are related to the Overland Pass Pipeline and associated expansion projects. The increase in growth capital expenditures for the Interstate Natural Gas Pipelines segment is primarily due to the Guardian Pipeline Expansion and Midwestern East Extension Project. Consolidated maintenance capital expenditures increased $8.4 million in 2005, compared with 2004, primarily due to pipeline replacements and compressor station overhauls by Northern Border Pipeline. Growth capital expenditures increased $16.4 million in 2005, compared with 2004, primarily due to the Chicago III Expansion, Southbound Expansion and Eastern Extension projects for our Interstate Natural Gas Pipelines segment.
The following table summarizes our 2007 projected growth and maintenance capital expenditures excluding AFUDC.
In May 2006, we entered into an agreement with Williams to form a joint venture called Overland Pass Pipeline Company, described in this section under “Recent Developments.” The pipeline project is estimated to cost approximately $433 million excluding AFUDC. In addition, we plan to invest approximately $216 million excluding AFUDC to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing these projects may include a combination of short- or long-term debt or equity. In 2007, we estimate that we will spend approximately $495 million excluding AFUDC related to these projects.
In January 2007 ONEOK Partner’s subsidiary Crestone Powder River announced that Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines resulting in 649 MMcf/d of additional capacity in the Powder River basin. The expansion will cost approximately $110 million and will occur in two phases with 240 MMcf/d in service by October 2007 and 409 MMcf/d by January 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. Crestone Powder River owns approximately 37 percent of Fort Union Gas Gathering.
Other significant projected growth expenditures for 2007 include approximately $22 million related to the Midwestern Gas Transmission Eastern Extension Project and approximately $85 million excluding AFUDC related to the Guardian Pipeline Expansion and Extension Project. Additional information about these projects is included under “Recent Developments” on page 31. Financing for these projects may include borrowing under the 2006 Partnership Credit Agreement.
Cash Distributions - We distribute 100 percent of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively, after the effect of any incremental income allocations for incentive distributions to our general partner.
For 2006, we paid $167.0 million to our common and Class B unitholders and $98.5 million to our general partners for their general partner and incentive distribution interests. For both 2005 and 2004, we paid $148.5 million to our common unitholders and $11.2 million to our general partners for their general partner and incentive distribution interests.
The following increases have been made to our quarterly cash distributions since January 1, 2006.
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In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006, which was paid on May 15, 2006 to unitholders of record as of April 28, 2006.
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In July 2006, we increased our cash distribution to $0.95 per unit for the second quarter of 2006, which was paid on August 14, 2006 to unitholders of record as of July 31, 2006.
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In October 2006, we increased our cash distribution to $0.97 per unit for the third quarter of 2006, which was paid on November 14, 2006 to unitholders of record on October 31, 2006.
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In January 2007, we increased our cash distribution to $0.98 per unit for the fourth quarter of 2006, which was paid on February 14, 2007 to unitholders of record on January 31, 2007.
Additional information about our cash distributions is included under Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, and Item 13, Certain Relationships and Related Transactions and Director Independence.
ENVIRONMENTAL LIABILITIES
We are subject to multiple environmental laws and regulations affecting many aspects of our 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 our 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.
Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2006, 2005 or 2004 related to compliance with environmental regulations.
CASH FLOW ANALYSIS
Operating Cash Flows - Operating cash flows increased by $338.7 million for 2006 compared with 2005. The increase in operating cash flows was primarily the result of the acquisition of the ONEOK Energy Assets. Changes in components of working capital, net of the effect of the acquisition, increased operating cash flow by $127.5 million, compared with an increase of $3.7 million last year, primarily as a result of decreases in accounts receivable, decreases in inventories and prepayments and increases in accrued interest.
Operating cash flows increased $22.7 million in 2005, compared with 2004, primarily due to the increase in net margin from our Gathering and Processing segment and the sale of bankruptcy claims against Enron and Enron North America. Partially
offsetting these increases were lower operating cash flows due to unsold and discounted capacity on Northern Border Pipeline and higher interest payments on debt.
Investing Cash Flows - Cash used in investing activities was $1.3 billion for 2006, compared with $68.4 million for 2005. The increased use of cash was primarily related to the following:
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the acquisition of the ONEOK Energy Assets for approximately $1.35 billion of cash consideration, before adjustments;
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the acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us for approximately $77 million;
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payment to Williams of $11.6 million for initial capital expenditures in connection with the Overland Pass Pipeline Company natural gas liquids pipeline joint venture;
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increased capital expenditures primarily related to the ONEOK Energy Assets of $141.9 million; and
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an equity contribution to Northern Border Pipeline of $7.2 million, partially offset by the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million.
During 2006, we used borrowings from our Bridge Facility and 2006 Partnership Credit Agreement and cash provided by operating activities to fund our investing activities. The borrowings under our Bridge Facility and 2006 Partnership Credit Agreement were subsequently repaid with proceeds from the public offering of senior notes completed in the third quarter of 2006.
Cash used in investing activities was $68.4 million in 2005, compared with $20.9 million in 2004, primarily due to increased Interstate Natural Gas Pipelines segment capital expenditures in 2005 and the sale of gathering and processing assets in 2004. These investing activities were funded primarily with operating cash and borrowings under our credit facilities. In 2005 and 2004, capital expenditures totaled $59.9 million and $43.4 million, respectively.
In 2004, we sold our undivided minority interest in the Gregg Lake/Obed Pipeline for $14.0 million and two gathering systems in the Powder River Basin for $8.7 million.
Financing Cash Flows - Cash provided by financing activities was $696.3 million in 2006, compared with cash used in financing activities of $189.8 million in 2005.
Cash distributions to our general and limited partners for 2006 increased $105.9 million, compared with 2005, due to the increased available cash following the ONEOK Transactions described in this section under “Recent Developments.” We increased our cash distribution to $0.88 per unit for the first quarter of 2006, $0.95 per unit for the second quarter of 2006, $0.97 per unit for the third quarter of 2006 and $0.98 for the fourth quarter of 2006. Our cash distributions to our limited and general partner totaled $265.5 million for 2006.
Distributions to minority interests for 2006 decreased $60.5 million, compared with 2005, primarily due to the deconsolidation of Northern Border Pipeline. Distributions to minority interests for 2005 included distributions related to TC PipeLines’ 30 percent interest in Northern Border Pipeline prior to the sale.
We reported cash flow retained by ONEOK of $177.5 million in 2006, which represented the cash flows generated during the first quarter of 2006 by the ONEOK Energy Assets prior to the acquisition.
During the second quarter of 2006, we borrowed $1.05 billion under our Bridge Facility to finance a portion of the acquisition of the ONEOK Energy Assets and $77 million under the 2006 Partnership Credit Agreement to acquire the 66 2/3 percent interest in Guardian Pipeline not previously owned by us. During the third quarter of 2006, we completed our underwritten public offering of senior notes which yielded $1.39 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding under our Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement.
In March 2006, we borrowed $33 million under our 2006 Partnership 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.
In 2005, borrowings under Northern Border Pipeline’s and our revolving credit agreements were primarily used to repay amounts borrowed under previously existing credit agreements for Northern Border Pipeline and us. Total borrowings in 2005 were $165.0 million and debt repayments were $130.2 million. We also paid $2.8 million to terminate forward-starting interest rate swaps and distributions of $159.6 million to our limited and general partners in 2005.
In 2004, we borrowed $152.0 million under our credit agreement. Northern Border Pipeline borrowed $107.0 million under its credit agreement and received an equity contribution of $61.5 million from its minority interest holder. Northern Border Pipeline also terminated interest rate swap agreements with a total notional amount of $225 million and received $7.6 million. We and Northern Border Pipeline used the cash to repay $327.5 million of debt, which included a $75 million redemption of Northern Border Pipeline’s senior notes due in 2007 and a related $4.8 million redemption premium.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2006, and reflects the deconsolidation of Northern Border Pipeline due to the sale of a 20 percent interest in Northern Border Pipeline, consolidation of Guardian Pipeline due to the acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us and additional contractual obligations resulting from the ONEOK Transactions. Additional information about these transactions, which occurred during the second quarter of 2006, is included in this section under “Recent Developments.”
For further discussion of the debt and operating lease agreements, see Notes F and K, respectively, of Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Long-term Debt - Long-term debt as reported on our Consolidated Balance Sheets includes unamortized debt discount and the mark-to-market effect of interest rate swaps.
Interest Payments on Debt - Interest expense is calculated by taking long-term debt and multiplying it by the respective coupon rates, adjusted for active swaps.
Operating Leases - Our operating leases include office space, vehicles, lease and easement obligations, and equipment. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides processing and related services at the Bushton Plant through 2012. In exchange for such services, we pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of OBPI’s obligations under equipment leases covering the Bushton Plant.
Purchase Commitments - Purchase commitments include purchases related to our growth capital expenditures and other right of way commitments.
Firm Transportation Contracts - Firm transportation agreements with our Gathering and Processing segment’s joint ventures require minimum monthly payments.
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” or other similar phrases.
You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
•
the effects of weather and other natural phenomena on our operations, demand for our services and energy prices;
•
competition from other United States and Canadian energy suppliers and transporters as well as alternative forms of energy;
•
the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil;
•
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;
•
risks of trading and hedging activities as a result of changes in energy prices or the financial condition of our counterparties;
•
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
•
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;
•
the ability to market pipeline capacity on favorable terms;
•
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
•
the mechanical integrity of facilities operated;
•
the effects of changes in governmental policies and regulatory actions, including changes with respect to income taxes, environmental compliance, authorized rates or recovery of gas costs;
•
the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving regulatory authorities or any other local, state or federal regulatory body, including the FERC;
•
actions by rating agencies concerning our credit ratings;
•
the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control;
•
our ability to access capital at competitive rates or on terms acceptable to us;
•
demand for our services in the proximity of our facilities;
•
the profitability of assets or businesses acquired by us;
•
the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
•
the impact and outcome of pending and future litigation;
•
our ability to successfully integrate the operations of the assets acquired from ONEOK with our current operations;
•
our ability to successfully transfer administrative functions of our interstate pipelines segment from Omaha to Tulsa;
•
performance of contractual obligations by our customers;
•
the uncertainty of estimates, including accruals;
•
our ability to control operating costs; and
•
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities.
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
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could 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 due to interest rate and commodity price volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We may use financial instruments, including forwards, swaps, collars and futures, to manage the risks of certain identifiable or anticipated transactions and achieve a more predictable cash flow. Our risk management function follows established policies and procedures to monitor interest rates and natural gas and natural gas liquids marketing activities to ensure our hedging activities mitigate market risks. We do not use financial instruments for trading purposes.
In accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we record financial instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of financial instruments using available market information and appropriate valuation techniques. Changes in financial instruments’ fair value are recognized in earnings unless the instrument qualifies as a hedge under Statement 133 and meets specific hedge accounting criteria. Qualifying financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income (loss) for a cash flow hedge.
INTEREST RATE RISK
General - We are subject to the risk of interest rate fluctuation in the normal course of business. We manage interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. Fixed rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2006, the interest rate on 92.6 percent of our long-term debt was fixed after considering the impact of interest rate swaps.
At December 31, 2006, a 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by $1.6 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 - During 2004 and 2005, we terminated interest rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2006 for all terminated swaps was $3.2 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:
Currently, $150 million of fixed rate debt is swapped to floating. The floating rate debt is based on six-month LIBOR. At December 31, 2006, we recorded a net liability of $3.2 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $3.2 million to recognize the change in the fair value of the related hedged liability. See Note G of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our interest rate
swaps. Total swap savings for 2006 were $2.0 million, compared with the savings of $6.1 million in 2005. Total swap savings for 2007 are expected to be $2.5 million.
COMMODITY PRICE RISK
Our Pipelines and Storage and Interstate Natural Gas Pipelines segments are exposed to commodity price risk because our intrastate and interstate pipelines collect natural gas from their customers for operations or as part of their fee for services provided. When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines must buy or sell natural gas, or use natural gas from inventory, and are exposed to commodity price risk. At December 31, 2006, there were no hedges in place with respect to natural gas price risk from our intrastate and interstate pipeline operations.
Our Natural Gas Liquids segment 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. We have not entered into any hedges with respect to our NGL marketing activities.
Our Gathering and Processing segment is exposed to commodity price risk primarily as a result of revenue from the sale of commodities received in exchange for our services. Our primary exposures arise from the relative price differential between natural gas and NGLs with respect to our keep-whole processing contracts and the sale of natural gas, NGLs and condensate with respect to our POP contracts. To a lesser extent, we are exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. We use commodity derivative contracts and fixed-price physical contracts, including NYMEX-based futures, collars and over-the-counter swaps, which are all designated as cash flow hedges, to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations. The following table sets forth our Gathering and Processing segment’s hedging information for 2007.
Our commodity price market risk is estimated as a hypothetical change in the price of natural gas, NGLs and crude oil at December 31, 2006. Our condensate sales are based on the price of crude oil. We estimate that a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.4 million, excluding the effects of hedging. We estimate that a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $2.1 million, excluding the effects of hedging. We estimate that a $0.10 per MMBtu increase in the price of natural gas would decrease annual net margin by approximately $0.1 million, excluding the effects of hedging. The above estimates of commodity price risk do not include any effects on demand for our services that might be caused by, or arise in conjunction with, price changes. For example, increased commodity prices may reduce demand for our storage and transportation services or may be caused by factors, such as weather, that increase demand for such services.
See Note G of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our hedging activities.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of ONEOK Partners GP, L.L.C. as General Partner of ONEOK Partners, L.P. and
to the Unitholders:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting (Item 9A), that ONEOK Partners, L.P. (the Partnership) (formerly Northern Border Partners, L.P.) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that ONEOK Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on COSO. Also, in our opinion, ONEOK Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ONEOK Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, cash flows, and changes in partners’ equity and comprehensive income for each of the years in the three-year period ended December 31, 2006, and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Tulsa, Oklahoma
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of ONEOK Partners GP, L.L.C. as General Partner of ONEOK Partners, L.P. and
to the Unitholders:
We have audited the accompanying consolidated balance sheets of ONEOK Partners, L.P. and subsidiaries (the Partnership) (formerly Northern Border Partners, L.P.) as of December 31, 2006 and 2005, and the related consolidated statements of income, cash flows, and changes in partners’ equity and comprehensive income for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Partnership’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 Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U. S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of ONEOK Partners, L.P.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Tulsa, Oklahoma
February 28, 2007
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
See accompanying Notes to the Consolidated Financial Statements
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to the Consolidated Financial Statements
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to the Consolidated Financial Statements
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY AND COMPREHENSIVE INCOME
See accompanying Notes to the Consolidated Financial Statements
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY AND COMPREHENSIVE INCOME
(Continued)
ONEOK PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF ACCOUNTING POLICIES
Nature of Operations - ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.” We own and manage natural gas gathering, processing, storage and interstate and intrastate pipeline assets and natural gas liquids gathering and distribution pipelines, storage and fractionators, connecting much of the natural gas and NGL supply in the Mid-Continent region with key market centers. We also own a 50 percent interest in a leading transporter of natural gas imported from Canada into the United States.
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.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
We assess our goodwill and intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. See Note C 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.
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 and under Statement 142, is not subject to amortization but rather to impairment testing pursuant to APB No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with APB Opinion No. 18.
We do not currently anticipate any additional goodwill or asset impairments to occur within the next year, but if such events were to occur over the long-term, the impact could be significant to our financial condition and results of operations.
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.
Significant Accounting Policies
Principles of Consolidation and Use of Estimates - Our consolidated financial statements include the assets, liabilities and results of operations for our majority-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. We account for our investments that we do not control by the equity method of accounting. Under this method, an investment is carried at its acquisition cost, plus the equity in undistributed earnings or losses since acquisition. Minority interest for 2006 primarily represents the 66 2/3 percent interest in Guardian Pipeline that we did not own until we acquired these interests in April 2006. Minority interest for 2005 represents the 30 percent interest in Northern Border Pipeline owned by TC Pipelines when Northern Border Pipeline’s results were consolidated.
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.
Regulation - Our intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC and RRC. Our interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC. Our Interstate Natural Gas Pipelines segment and portions of our Pipelines and Storage 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 allow us to defer recognition of certain costs and permit recovery of the amounts 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 by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations are no longer subject to the provisions of Statement 71, a write-off of regulatory assets and costs not recovered may be required.
At December 31, 2006 and 2005, we recorded regulatory assets, which are currently being recovered or are expected to be recovered from our customers, of approximately $9.2 million and $17.7 million, respectively. Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 40 years. These assets are reflected in other assets on our Consolidated Balance Sheets.
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 are accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities which have jurisdiction over our regulated operations have not required us to track this amount; rather these costs are addressed prospectively as depreciation rates are set in each general rate order. We have made an estimate of our removal cost liability using current rates since the last general rate order in each of our jurisdictions. However, significant uncertainty exists regarding the ultimate determination of this liability pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory authorities and the liability may be adjusted as more information is obtained.
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.
Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. Our Gathering and Processing segment records operating revenue when gas is processed in or transported through company facilities. Our Natural Gas Liquids segment records operating revenues based upon contracted services and actual volumes
exchanged or stored under service agreements in the period services are provided. Operating revenue for our Pipelines and Storage segment and Interstate Natural Gas Pipelines segment is recognized based upon contracted capacity and actual volumes transported and stored under service agreements in the period services are provided.
Income Taxes - We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in our Consolidated Statements of Income, is included in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and income tax purposes cannot be readily determined, as we do not have access to all information about each partner’s tax attributes related to us.
Our corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for under the asset and liability method. Deferred income tax assets and liabilities are recognized by these entities for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax basis and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Except for the companies whose accounting policies conform to Statement 71, the effect on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. For the companies whose accounting policies conform to Statement 71, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the period that includes the enactment date.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are evaluating our tax positions and anticipate FIN 48 will not have a significant impact on our results of operations.
Property - The following table sets forth our property, by segment, for the periods presented.
Regulated Property - Regulated properties are stated at cost, which includes AFUDC. The AFUDC represents the capitalization of the estimated average cost of equity funds used during the construction of major projects and is recorded as other income. At December 31, 2006 and 2005, property, plant and equipment on our Consolidated Balance Sheets included construction work in progress of $100.5 million and $17.7 million, respectively.
Certain maintenance and repairs are charged directly to expense. Generally, the cost of property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of an entire operating unit or system are recognized in income.
We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.
The average depreciation rates for our regulated property are set forth in the following table for the periods indicated.
Other Property - Gas processing plants, natural gas liquids fractionation plants and all other properties are stated at cost. Gas processing plants, natural gas liquids fractionation plants and all other property and equipment are depreciated using the straight-line method over the estimated useful life.
Capitalized Interest - We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2006, 2005 and 2004 was $1.2 million, $0.8 million and $0.4 million, respectively.
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 remediation feasibility study. Such accruals are adjusted as further information becomes available or as circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Inventory, Natural Gas Imbalances and Commodity Exchanges - Inventory is valued at the lower of cost or market. The values of current natural gas and NGLs in storage are determined using the weighted average cost method. Noncurrent natural gas in storage is classified as property and valued at cost. Materials and supplies are valued at average cost. Natural gas 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.
Derivatives and Risk Management - We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve more predictable cash flows. 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 and time value.
Market value changes result in a change in the fair value of our derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, 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, condensate and NGLs and associated equity margins. 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 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 other comprehensive income (loss) and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.
Many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.
See Note G for a discussion of derivatives and risk management activities.
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.
Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2006 presentation. These reclassifications did not impact previously reported net income or partners’ equity.
Other
In September 2006, the SEC staff issued SAB Topic 1N, “Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how to quantify the effect of an error on the financial statements. SAB 108 is effective for our year ended December 31, 2006. We have reviewed the applicability of SAB 108 to our operations and have determined that it did not have an impact on our consolidated financial statements.
In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
B. ACQUISITIONS AND DIVESTITURES
Overland Pass Pipeline Company - In May 2006, we 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 will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. As the 99 percent owner of the joint venture, we will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing us for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer of 2007, with start up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million excluding AFUDC. During 2006, we paid $11.6 million to Williams for acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. In addition, we plan to invest approximately $216 million excluding AFUDC to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and federal regulatory authorities.
The ONEOK Transactions - In April 2006, we acquired certain companies comprising ONEOK’s former gathering and processing, natural gas liquids, and pipelines and storage segments, collectively referred to as the “ONEOK Energy Assets,” from ONEOK, the parent company of our general partner, in a series of transactions collectively referred to as the “ONEOK Transactions.” As part of the ONEOK Transactions, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us, under a Purchase and Sale Agreement between an affiliate of ONEOK and an affiliate of TransCanada. As a result, ONEOK owns our entire 2 percent general partner interest and controls us.
We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units, which, when combined with its general partner interest, increases its total interest in us to approximately 45.7 percent. We also used $1.05 billion drawn under our $1.1 billion, 364-day credit agreement (the Bridge
Facility), coupled with the proceeds from the sale of a 20 percent partnership interest in Northern Border Pipeline, to finance the transaction.
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” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Our Partnership Agreement provides for the right to replace the general partner by a vote of greater than a simple majority of the limited partner interests not held by the general partner and, accordingly, under the guidance in EITF 04-5, ONEOK is deemed to have control for accounting purposes. ONEOK elected to use the prospective method and began to consolidate our operations in their consolidated financial statements as of January 1, 2006. As ONEOK is deemed to control us under the requirements of EITF 04-5, the ONEOK Transactions are accounted for as a transaction between entities under common control and the transaction is excluded from the accounting indicated by Statement 141, “Business Combinations.” Accordingly, ONEOK’s historical cost basis in the ONEOK Energy Assets is transferred to us in a manner similar to a pooling of interests. The difference between the historical cost basis of the net assets acquired of $2.7 billion and the cash paid has been assigned to the value of the Class B limited partner units issued to ONEOK and their general partner interest in us. These assets and their related operations are included in our consolidated financial statements as of January 1, 2006. The following table shows the impact to our Consolidated Balance Sheets for the ONEOK Energy Assets as of December 31, 2005.
Since the ONEOK Transactions were not completed until April 2006, the income and cash flow from the ONEOK Energy Assets for the first quarter of 2006 were retained by ONEOK. In our Consolidated Statements of Cash Flows, we reported cash flow retained by ONEOK of $177.5 million, which represents the cash flows generated from these companies while they were owned by ONEOK. The following table shows the impact to our Consolidated Statements of Income for the ONEOK Energy Assets prior to our acquisition.
Prior to the acquisition, the ONEOK Energy Assets were included in the consolidated state and federal income tax returns of ONEOK and, accordingly, current taxes payable were allocated to the ONEOK Energy Assets based on ONEOK’s effective tax rate. Income tax liabilities and provisions for income tax expense for the ONEOK Energy Assets, as presented in the preceding table, were calculated on a stand-alone basis. Our Consolidated Statements of Income for 2006 includes income tax expense recorded for the ONEOK Energy Assets of $22.2 million for the first quarter of 2006. In conjunction with the ONEOK Transactions, all income tax liabilities of ONEOK Energy Assets at the time of the ONEOK Transactions were retained by ONEOK.
Income from the ONEOK Energy Assets for the first quarter of 2006 also reflects interest expense of $21.3 million, which represents interest charged on long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was retained by ONEOK as part of the ONEOK Transactions.
Under the terms of the ONEOK Transactions, we recorded a $72.6 million purchase price adjustment related to a finalized working capital settlement. The working capital settlement is reflected as an increase to the value of the Class B units and was approved by our Audit Committee.
The unaudited pro forma information in the table below presents a summary of our results of operations as if the acquisition of the ONEOK Energy Assets 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 of the ONEOK Energy Assets had actually occurred on the dates indicated or results that may be expected in the future.
The units issued to ONEOK were the newly created Class B limited partner units. The Class B units are currently subordinated to the common units with respect to the payment of the minimum quarterly distributions, which are $0.55 per unit, and thereafter, the holders of the Class B units have the same right to receive minimum quarterly distributions as those received by the holders of the common units. If distributions to all unitholders exceed $0.55 per unit, the holders of common units and the holders of Class B units receive the same distribution per unit. The Class B units have limited voting rights.
We will hold a special election for holders of common units on March 29, 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to our Partnership Agreement. The proposed amendments to our Partnership Agreement would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the conversion and the amendments are approved by the common unitholders, the Class B units will automatically convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the Class B unit distribution would increase to 110 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and amendments, the amount payable on such Class B units would increase to 123.5 percent of the distributions payable with respect to the common units, and 125 percent of the distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated to the common units with respect to the minimum quarterly distributions above unless and until the conversion described above has been approved.
Disposition of 20 Percent Partnership Interest in Northern Border Pipeline - In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline and an affiliate of TransCanada will become the operator of the pipeline in April 2007. Under Statement 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary should not be consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither we nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. We are no longer consolidating Northern Border Pipeline as of January 1, 2006, the effective date of the sale. The amounts we previously reported as assets, liabilities and equity associated with Northern Border Pipeline were reclassified as an investment under the equity method. This change does not affect previously reported net income or partners’ equity.
The following table shows the reconciliation of our investment in Northern Border Pipeline at December 31, 2005.
Acquisition of Guardian Pipeline Interests - In April 2006, we acquired the 66 2/3 percent interest in Guardian Pipeline not previously owned by us for approximately $77 million, increasing our ownership to 100 percent. We used borrowings from our credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was retroactive to January 1, 2006. Prior to the transaction, our 33 1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.
Gregg Lake/Obed Pipeline - Border Midstream sold its undivided minority interest in the Gregg Lake/Obed Pipeline (Gregg Lake/Obed) for $14.0 million, effective December 1, 2004. Operating revenues, operating expenses and other income and expense have been classified as discontinued operations. Operating revenues for discontinued operations for the year ended December 31, 2004 were $3.0 million. No operating revenues were recognized in 2005. Discontinued operations on the accompanying Consolidated Statements of Income consist of the following amounts.
C. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Carrying Amounts - The following table reflects the changes in the carrying amount of goodwill for the period indicated.
2006 Activity - The acquisition of the ONEOK Energy Assets resulted in $214.8 million of additional goodwill on our 2006 Consolidated Balance Sheet.
Our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us resulted in the recognition of $5.7 million of additional goodwill and reclassification of $1.7 million to goodwill, which had been previously included in our investment in unconsolidated affiliates.
Goodwill increased by approximately $27.9 million relating to the 2003 acquisition of Viking Gas Transmission. In our accounting for the acquisition, we had allocated the entire purchase price 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.
See Black Mesa section of this Note for discussion of goodwill impairment.
2005 Activity - There was no change in the carrying amounts of goodwill during 2005.
Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of next assets is referred to as equity method goodwill under Statement 142. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million and $185.8 million as of December 31, 2006 and 2005, respectively.
Intangible Assets
Our intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from ONEOK and are being amortized over an aggregate weighted-average period of 40 years. Amortization expense for 2006 was $7.7 million and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets at December 31, 2006.
Impairment Test
We adopted Statement 142, “Goodwill and Other Intangible Assets” on January 1, 2002, and elected to use a fourth-quarter annual goodwill impairment testing date. In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. Prior to the change we had segments, and companies within segments, performing the annual goodwill impairment test as of the fourth quarter and as of January 1. The multiple testing dates resulted from our acquisition of the ONEOK Energy Assets in April 2006 and were due to ONEOK’s former gathering and processing, natural gas liquids, and pipelines and storage segments using a January 1 testing date. We believe that this change in accounting principle is preferable because (1) ONEOK, which owns our general partnership interest and which consolidates us under EITF 04-5, is using a July 1 impairment testing date, (2) the test would be performed at the same time for all our segments, (3) performing the test as of the first day of the third quarter allows adequate time to complete the test while still providing time to report the impact of the test in our periodic filings for the third quarter, and (4) the third quarter is outside the normal operating cycle of most of our segments and coincides with our annual budget process, which results in more detailed budgeting and forecasting information available for use in the impairment analysis. There were no impairment charges resulting from the July 1, 2006, impairment testing, and no events indicating an impairment have occurred subsequent to that date.
Black Mesa
Black Mesa, which is included in our Other segment, consists of a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona, and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005.
Under a consent decree, Mohave agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding ongoing water and coal supply negotiations, Southern California Edison Company (SCE), a 56 percent owner of Mohave, filed a petition before the California Public Utilities Commission (CPUC) requesting that they either recognize the end of Mohave’s coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.
On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired, and our coal slurry pipeline operations were shut down as expected. In June 2006, SCE completed a comprehensive study of the water source, coal supply and transportation issues, and announced that it would no longer pursue the resumption of plant operations. In February 2007, another Mohave co-owner, Salt River Project, announced it was ending its efforts to return the plant to service. Negotiations among various parties involved with Black Mesa are ongoing.
During 2006, we reassessed our coal slurry pipeline operation as a result of the developments described above. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced, and a goodwill and asset impairment of $8.4 million and $3.6 million, respectively, was recorded as depreciation and amortization. The reduction to net income after income taxes was $10.6 million.
D. RATES AND REGULATORY ISSUES
The FERC regulates the rates and charges for transportation on our interstate natural gas pipelines. Interstate natural gas pipeline companies may not charge rates that have been determined to be unjust and unreasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. The rates, terms and conditions for service are found in each pipeline’s FERC-approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates.
Under the capacity release provisions of the interstate pipelines’ FERC tariffs, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it.
Settlement of Rate Case - In November 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its previous rate case. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding and accepted the proposed rates, but suspended their effectiveness until May 1, 2006. Beginning May 1, 2006, the new rates were collected subject to refund through September 30, 2006. Based on the settlement discussed below, the rates in effect prior to the rate case filing were collected for the months of October to December 2006, and did not result in collecting additional amounts subject to refund.
In September 2006, Northern Border Pipeline filed a stipulation and agreement that documented the settlement reached between Northern Border Pipeline and its participant customers and supported by the FERC trial staff. The uncontested settlement was certified in October 2006 by the administrative law judge and approved by the FERC in November 2006. Based on the settlement, Northern Border Pipeline refunded $10.8 million to its customers in the fourth quarter of 2006.
The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border Pipeline’s system. Beginning in 2007, overall rates were reduced, compared with rates prior to the filing, by approximately 5 percent. For the full transportation route from Port of Morgan, Montana to the Chicago area, the previous charge of approximately $0.46 per Dth is now approximately $0.44 per Dth, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant were increased from 2.25 percent to 2.40 percent. The settlement also provided for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth to approximately $0.29 per Dth for the full transportation route from Port of Morgan, Montana to the Chicago area. The settlement also included a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging these rates, and requires that Northern Border Pipeline file a rate case within six years.
Other - Midwestern Gas Transmission, Viking Gas Transmission, Guardian Pipeline and OkTex Pipeline have no timing requirements or restriction in regard to future rate case filings.
E. CREDIT FACILITIES
2006 Partnership Credit Agreement - In December 2006, we amended our 2006 Partnership Credit Agreement. This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA (net income before interest expense, income taxes and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland Pass Pipeline Company agreement from the covenant that limits our ability to enter into agreements that restrict our ability to grant liens to the lenders under the 2006 Partnership Credit Agreement.
In March 2006, we amended and restated the 2005 revolving credit agreement with certain financial institutions and increased the term for an additional five years, increased the facility to $750 million from $500 million, and lowered the pricing. The 2005 revolving credit agreement was renamed the 2006 Partnership Credit Agreement.
Under the 2006 Partnership Credit Agreement, we are required to comply with certain financial, operational and legal covenants. These requirements include:
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maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1, and
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maintaining a ratio of EBITDA (net income before interest expense, income taxes and depreciation and amortization) to interest expense of not less than 3 to 1.
If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement may become immediately due and payable. At December 31, 2006, we were in compliance with these covenants. At December 31, 2006, a letter of credit of $10 million was outstanding under the 2006 Partnership Credit Agreement. The letter of credit expires May 1, 2007.
Bridge Facility - In April 2006, we entered into a $1.1 billion 364-day credit agreement (the Bridge Facility) with a syndicate of banks and borrowed $1.05 billion to finance a portion of the acquisition of the ONEOK Energy Assets. In September 2006, we repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated in accordance with its terms.
Guardian Pipeline - Our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us resulted in the inclusion of outstanding amounts under Guardian Pipeline’s revolving note agreement on our 2006 Consolidated Balance Sheet. The revolving note agreement permits Guardian Pipeline to choose rates based on the prime commercial lending rate or LIBOR as the interest rate on its outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and specify the interest rate period. At December 31, 2006, Guardian Pipeline had $6.0 million outstanding under its $10 million revolving note agreement at an average interest rate of 6.59 percent, due January 2007. The Guardian Pipeline revolving credit agreement terminates in November 2007.
Guardian Pipeline’s revolving note agreement contains typical covenants, including financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1, and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the note agreement may become due and payable immediately. At December 31, 2006, Guardian Pipeline was in compliance with its financial covenants.
F. LONG-TERM DEBT
The following table sets forth our long-term debt for the periods indicated.
The aggregate maturities of long-term debt outstanding for years 2007 through 2011 are shown below.
Debt Issuance - In September 2006, we 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). We registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006.
We 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 our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of our non-guarantor subsidiaries. The Notes are non-recourse to our general partner.
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 our Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated September 25, 2006, between us 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 our ability to place liens on our property or assets and sell and lease back our property.
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. We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership, which is also consolidated. The Intermediate Partnership holds partnership interests and the equity in our subsidiaries as well as a 50 percent interest in Northern Border Pipeline at December 31, 2006, which is accounted for under the equity method.
The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro rata basis according to each partner’s percentage interest. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement. After we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC Pipelines in April 2006, the Northern Border Pipeline Management Committee adopted certain changes to its cash distribution policy related to financial ratio targets and capital contributions. The change was to define minimum equity to total capitalization ratios to be used by the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions. At December 31, 2006 and 2005, our equity in the net assets of Northern Border Pipeline was approximately $438 million and $640 million, respectively.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016, and October 1, 2036, respectively. We will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Viking Gas Transmission - In March 2006, we borrowed $33 million under our 2006 Partnership 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. The net loss from the redemption, including unamortized debt costs associated with the debt, has been capitalized as a regulatory asset and will be amortized to interest expense over the remaining life of the Viking Gas Transmission senior notes, as if such notes had not been redeemed. At December 31, 2006, the unamortized loss on reacquired debt included in other assets on our Consolidated Balance Sheet was $3.4 million.
Guardian Pipeline Master Shelf Agreement - Our acquisition of the 66 2/3 percent interest in Guardian Pipeline not previously owned by us resulted in the inclusion of $145.6 million of long-term debt on our 2006 Consolidated Balance Sheet. These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.86 percent. Guardian Pipeline’s master shelf agreement contains covenants which are substantially the same as those contained in Guardian Pipeline’s revolving note agreement, as previously described, except that beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1.
Northern Border Pipeline - Due to the deconsolidation of Northern Border Pipeline, we are not reporting its long-term debt subsequent to December 31, 2005.
Other - The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the aggregate of all the senior notes outstanding was approximately $2.04 billion and $1.17 billion at December 31, 2006 and 2005, respectively. We presently intend to maintain the current
schedule of maturities for the senior notes, which will result in no gains or losses on their respective repayment. The fair value of the 2006 Partnership Credit Agreement and the Guardian Pipeline revolving note agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.
G. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes.
Cash Flow Hedges - Our Gathering and Processing segment periodically enters into commodity derivative contracts and fixed-price physical contracts. Our Gathering and Processing segment primarily utilizes NYMEX-based futures, collars and over-the-counter swaps, which are designated as cash flow hedges, to hedge its exposure to volatility in the gross processing spread and the price of natural gas, NGLs and condensate. During 2006, this segment recognized net gains from the settlement of derivative contracts of $4.8 million. During 2005 and 2004, this segment recognized losses of $4.8 million and $9.4 million, respectively. At December 31, 2006, the accompanying Consolidated Balance Sheet reflected an unrealized loss of $2.2 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities. In 2007, if prices remain at current levels, the Gathering and Processing segment expects to reclassify approximately $2.2 million from accumulated other comprehensive income (loss) as a decrease to operating revenue as a result of hedge settlement, which would offset higher operating revenues in the physical market. Net gains and losses related to the ineffective portion of our hedges are reclassified out of accumulated other comprehensive income (loss) to operating revenues in the period the ineffectiveness occurs. Ineffectiveness related to these cash flow hedges resulted in a gain of approximately $4.5 million for 2006. Ineffectiveness related to these cash flow hedges was not material in 2005 or 2004. There were no losses during 2006, 2005 or 2004 due to the discontinuance of cash flow hedge treatment.
Fair Value Hedges - During 2004 and 2005, we terminated interest rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2006 for all terminated swaps was $3.2 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.
Currently, $150 million of fixed rate debt is swapped to floating. The floating rate debt is based on six-month LIBOR. At December 31, 2006, we recorded a net liability of $3.2 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $3.2 million to recognize the change in the fair value of the related hedged liability. See Note F for additional discussion of long-term debt.
Based on the actual performance through December 31, 2006, the weighted average interest rate on the $150 million of debt increased from 7.10 percent to 7.97 percent.
H. UNCONSOLIDATED AFFILIATES
Investment in Unconsolidated Affiliates - The following table sets forth our investment in unconsolidated affiliates for the periods indicated.
Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated.
Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.
I. NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deducting the general partner’s allocation, by the weighted average number of outstanding limited partner units. The general partner owns a 2 percent interest in us and also owns incentive distribution rights that provide for an increasing proportion of cash distributions made by us as the distributions made to limited partners increase above specified levels. For purposes of our calculation of net income per unit, net income is generally allocated to the general partner as follows: 1) an amount based upon the 2 percent general partner interest in net income; and 2) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared with respect to the period. The amount of incentive distributions allocated to our general partners totaled $31.6 million, $8.0 million and $8.0 million for 2006, 2005 and 2004, respectively. The distribution amount to partners shown on the accompanying Consolidated Statements of Changes in Partners’ Equity and Comprehensive Income included incentive distributions paid to the general partner in 2006, 2005 and 2004 of approximately $23.1 million, $8.0 million and $8.0 million, respectively. Gains resulting from interim capital transactions, as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement provides that if such distributions were made, the incentive distribution rights would not apply. Accordingly, the gain on sale of assets for 2006 had no impact on the incentive distribution rights.
As discussed in Note B, we completed the ONEOK Transactions during the second quarter of 2006; however, for accounting purposes, the transactions were accounted for retroactive to January 1, 2006. Net income from the ONEOK Energy Assets prior to the April 2006 acquisition was approximately $35.8 million and has been reflected in our earnings for 2006. For purposes of our calculation of 2006 income per unit, these pre-acquisition earnings were allocated to ONEOK as they retained the related cash flow for that period.
On January 16, 2007, we declared a cash distribution of $0.98 per unit ($3.92 per unit on an annualized basis) for the fourth quarter of 2006. The distribution was paid on February 14, 2007, to unitholders of record on January 31, 2007.
J. PARTNERS’ EQUITY
At December 31, 2006, we had 46,397,214 common units and 36,494,126 Class B Units. ONEOK owns all of the Class B Units, approximately 500,000 common units, and the 2 percent general partner interest in us. The Class B Units, common units and the general partner interest held by ONEOK and its affiliates together constitute a 45.7 percent interest in us.
Under our Partnership Agreement, in conjunction with the issuance of additional common units, our general partner is required to make equity contributions to us in order to maintain a 2 percent general partner interest.
Under our Partnership Agreement, we make distributions to our partners with respect to each calendar quarter in an amount equal to 100 percent of our available cash within 45 days following the end of each quarter. Available cash generally consists of all our cash receipts adjusted for our cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to our 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 common 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.
Our income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the general partner. For the years ended December 31, 2006, 2005 and 2004, incentive distributions allocated to the general partners totaled $31.6 million, $8.0 million and $8.0 million, respectively.
K. COMMITMENTS AND CONTINGENCIES
Legal Proceedings - Our ONEOK Field Services Company subsidiary is a defendant in litigation brought by Praxair, Inc. (Praxair) in which Praxair alleges that ONEOK Field Services Company wrongfully declared force majeure under an agreement with Praxair for delivery of helium. Praxair is claiming damages of $41.5 million for breach of contract. Trial in this case is currently scheduled for March 2007. We intend to continue to vigorously defend this case.
In addition, we are a party to other litigation matters and claims that are in the normal 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.
Environmental Liabilities - We are subject to multiple environmental laws and regulations affecting many aspects of our 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 our 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.
Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2006, 2005 or 2004 related to compliance with environmental regulations.
Firm Transportation Obligations and Other Commitments - We have firm transportation agreements with Fort Union Gas Gathering and Lost Creek. The Fort Union Gas Gathering agreement expires in 2009 and the Lost Creek agreement expires in 2010. Under these agreements, we must make specified minimum payments to Fort Union Gas Gathering and Lost Creek each month. We recorded expenses of $12.0 million, $11.7 million and $11.8 million for 2006, 2005 and 2004, respectively,
related to these agreements. At December 31, 2006, the estimated aggregate amounts of such required future payments were $11.8 million for 2007, $11.9 million for 2008, $11.3 million for 2009 and $3.7 million for 2010.
At December 31, 2006, we have guaranteed certain of our unconsolidated affiliates’ performance in connection with credit agreements that expire in March 2009 and September 2009. At December 31, 2006, guarantees were $4.4 million.
Operating Leases - Future minimum lease payments under non-cancelable operating leases on office space, pipeline equipment, rights-of-way and vehicles are shown in the table below.
Expenses incurred related to these lease obligations for 2006, 2005 and 2004, were $15.0 million, $3.6 million and $3.8 million, respectively.
L. INCOME TAXES
Components of the income tax provision applicable to continuing operations and income taxes paid by our corporate subsidiaries are shown in the table below.
Taxes retained by ONEOK represent taxes accrued for the ONEOK Energy Assets during the first quarter of 2006. In conjunction with the ONEOK Transactions, all income tax liabilities of the ONEOK Energy Assets at the time of the ONEOK Transactions were retained by ONEOK. See Note B for additional discussion of the ONEOK Transactions.
The difference between the statutory federal income tax rate and our effective income tax rate is summarized in the table below.
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.
We had available, at December 31, 2006, approximately $8.0 million of tax benefits related to net operating loss carry forwards, 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 carry forwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.
M. SEGMENTS
ONEOK Energy Assets - The acquisition of the ONEOK Energy Assets in April 2006 is accounted for in our consolidated financial statements effective January 1, 2006. In connection with these transactions, we formed our Natural Gas Liquids segment and our Pipelines and Storage segment.
Segment Descriptions - Our business is divided into four reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our management and the Board of Directors of our general partner. Our reportable segments are strategic business units that offer different services. Each segment is managed separately based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (1) our Gathering and Processing segment, which primarily gathers and processes raw natural gas; (2) our Natural Gas Liquids segment, which primarily gathers, treats and fractionates raw NGLs and stores and markets purity NGL products; (3) our Pipelines and Storage segment, which primarily operates regulated intrastate natural gas transmission pipelines, natural gas storage facilities and regulated natural gas liquids gathering and distribution pipelines; and (4) our Interstate Natural Gas Pipelines segment, which primarily operates our interstate natural gas transmission pipelines that are regulated by the FERC. Certain assets of the Pipelines and Storage segment are regulated by the FERC and by the OCC, KCC and RRC.
Accounting Policies - The accounting policies of the segments are described in Note A. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A significant portion of our Pipelines and Storage segment’s revenues are from ONEOK and its subsidiaries, which utilize both transportation and storage services. Our Interstate Natural Gas Pipelines segment provides transportation services to ONEOK and its subsidiaries. Corporate overhead costs relating to a reportable segment are allocated for the purpose of calculating operating income.
Northern Border Pipeline was no longer consolidated effective January 1, 2006. For our Interstate Natural Gas Pipelines segment, Northern Border Pipeline’s revenues represented approximately 85 percent and 86 percent of the segment’s revenues in 2005 and 2004, respectively.
Customers - The main customers for our Gathering and Processing segment are primarily major and independent oil and gas production companies. Our Natural Gas Liquids segment’s customers are primarily gathering and processing companies and petrochemical and refining companies. Companies served by our Pipelines and Storage segment and Interstate Natural Gas Pipelines segment include local distribution companies, power generating companies, natural gas marketing companies and petrochemical companies.
In 2006, we had no single external customer from which we received 10 percent or more of our consolidated revenues. For 2005 and 2004, we had two customers that accounted for more than 10 percent of our total consolidated operating revenues. In 2005, Lodgepole Energy Marketing (Lodgepole) and BP Canada accounted for $123.2 million (18 percent) and $114.4 million (17 percent), respectively, of our consolidated operating revenues. In 2004, Lodgepole and BP Canada accounted for $82.0 million (14 percent) and $93.2 million (16 percent), respectively, of our consolidated operating revenues. Operating revenues from Lodgepole are recorded in our Gathering and Processing segment. Both our Gathering and Processing segment and Interstate Natural Gas Pipelines segment have recorded operating revenues from BP Canada.
Operating Segment Information - The following tables set forth certain operating segment financial data for the periods indicated.
(a) - Our Interstate Natural Gas Pipelines segment's operations are regulated.
(b) - Our Pipelines and Storage segment has regulated and non-regulated operations. Our Pipelines and Storage segment's regulated operations had revenues of $205.5 million and operating income of $78.9 million for the year ended December 31, 2006.
(a) - Our Interstate Natural Gas Pipelines segment's operations are regulated.
(a) - Our Interstate Natural Gas Pipelines segment's operations are regulated.
We evaluate our performance based on EBITDA, earnings before interest, taxes, depreciation and amortization less AFUDC. Management uses EBITDA to compare the financial performance of its segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparison with peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. EBITDA calculations may vary from company to company, so our computation of EBITDA may not be comparable with a similarly titled measure of another company.
The following tables set forth the reconciliation of net income to EBITDA by operating segment for the periods indicated.
N. QUARTERLY FINANCIAL DATA (UNAUDITED)
The first quarter 2006 amounts in the above table have been restated to reflect the acquisition of the ONEOK Energy Assets. This restatement impacted all amounts except net income per unit. See Note B for discussion of ONEOK Energy Assets consolidation as of January 1, 2006.
Net margin for all quarters of 2005 and the first and second quarter of 2006 were restated to be consistent with the classification used in our September 30, 2006 Quarterly Report on Form 10-Q and in this Annual Report on Form 10-K.
O. RELATED-PARTY TRANSACTIONS
Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A significant portion of our Pipelines and Storage segment’s revenues are from ONEOK and its subsidiaries, which utilize both transportation and storage services. Our Interstate Natural Gas Pipelines segment provides transportation services to ONEOK and its subsidiaries.
As part of the ONEOK Transactions, we acquired contractual rights to process natural gas at the Bushton Gas Processing Plant (the Bushton Plant) that is leased by OBPI. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides processing and related services at the Bushton Plant through 2012. In exchange for such services, we pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of OBPI’s obligations under equipment leases covering the Bushton Plant. On January 1, 2007, the Bushton Plant was
temporarily idled. We are in the process adding new facilities and making other changes at the Bushton Plant as part of our Overland Pass Pipeline Company project and associated expansions.
In April 2006, we entered into a Services Agreement with ONEOK, ONEOK Partners GP and NBP Services (the Services Agreement) that replaced the Administrative Services Agreement between us and NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK will provide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP will continue to operate our interstate natural gas pipeline assets according to each pipeline’s operating agreement, except for the operating agreement between ONEOK Partners GP and Northern Border Pipeline, which will terminate effective April 1, 2007. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its responsibilities.
ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financing services, employee benefits provided through ONEOK’s benefit plans, administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and wages. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.
Prior to our April 2006 acquisition, the ONEOK Energy Assets balance sheet included long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was eliminated in conjunction with our acquisition of the ONEOK Energy Assets.
An affiliate of ONEOK enters into some of the commodity derivative contracts at the direction of and on behalf of our Gathering and Processing segment. See Note G for a discussion of our derivative instruments and hedging activities.
At December 31, 2005, and 2004, Northern Border Pipeline has contracted firm capacity held by one shipper affiliated with ONEOK. ONEOK Energy Services became affiliated with Northern Border Pipeline on November 17, 2004, in connection with ONEOK’s purchase of Northern Plains. Revenue from ONEOK Energy Services for 2005 and the period from the date of affiliation to December 31, 2004, was $7.7 million and $1.1 million, respectively. At December 31, 2005, Northern Border Pipeline had outstanding receivables from ONEOK Energy Services of $0.9 million.
The following table sets forth the transactions with related parties for the periods shown.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Under the supervision and with the participation of senior management, including our Chief Executive Officer (“Principal Executive Officer”) and our Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the 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, 2006, to ensure the timely disclosure of required information in our periodic SEC filings.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2006.
Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein (Item 8).
Changes in Internal Controls Over Financial Reporting
We have made changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal year ended December 31, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as described below.
In April 2006, we entered into a services agreement with ONEOK and also acquired the ONEOK Energy Assets. In addition, ONEOK now owns 100 percent of our general partner interest. The operations previously managed in our Denver, Colorado office have been moved to Tulsa, Oklahoma while our Omaha, Nebraska office operations are anticipated to be completely transitioned to Tulsa by April 2007. The majority of the financial reporting functions that have been moved were absorbed into ONEOK’s existing internal control structure. For financial reporting functions that are moving from Omaha, the adaptation and modification of our internal control structure will continue into 2007. We do not expect these changes to have an adverse affect on our internal control over financial reporting.
In July 2005, ONEOK acquired natural gas liquids assets from Koch, which we subsequently acquired as part of the ONEOK Energy Assets. As part of our integration activities that continued into 2006, we developed and incorporated new controls and procedures related to the ONEOK Energy Assets into our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Partnership Board of Directors and Audit Committee
We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP, consisting of six members elected by ONEOK, the parent corporation of our general partner. We refer to the Board of Directors of ONEOK Partners GP as our Board of Directors. Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to comply with certain requirements of the NYSE. Accordingly, we do not comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner be comprised of a majority of independent directors. In addition, we do not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors. However, our Board of Directors has affirmatively determined that three members of our Board of Directors, Gary N. Petersen, Gerald B. Smith and Gil J. Van Lunsen, have no material relationship with us and are “independent” under our Governance Guidelines and the listing standards of the NYSE.
Our Board of Directors has an Audit Committee consisting of the three members of the Board of Directors who are each independent under our Governance Guidelines and the listing standards of the NYSE. The Audit Committee has oversight responsibility with respect to the integrity of our financial statements, the performance of our internal audit function, the independent auditor’s qualification and independence and compliance with legal and regulatory requirements. The Audit Committee directly appoints, retains, evaluates and may terminate our independent auditor. The Audit Committee reviews our annual and quarterly financial statements and resolves, if necessary, any significant disputes between management and the independent auditor that arise in connection with the preparation of our financial statements. The Audit Committee also has the authority to review specific matters that may present a conflict of interest in order to determine if the resolution of such conflict proposed by our Board of Directors is fair and reasonable to our unitholders. The Audit Committee has all other responsibilities required by the applicable NYSE listing standards and applicable SEC rules. The Board of Directors of our general partner has adopted a written charter for our Audit Committee.
The members of our Board of Directors and Audit Committee are not elected by unitholders. Accordingly, we do not have a procedure by which security holders may recommend nominees to our Board of Directors or Audit Committee. The persons designated as our executive officers serve in that capacity at the discretion of our Board of Directors. Audit Committee members are elected, and may be removed, by our Board of Directors.
Communications with Directors
Our Board of Directors believes that it is management’s role to speak for us. Our Board also believes that any communications between members of the Board and interested parties, including unitholders, should be conducted with the knowledge of our president and chief executive officer. Interested parties, including unitholders, may contact one or more members of our Board of Directors, including non-management directors and non-management directors as a group, by writing to the director or directors in care of our corporate secretary at our principal executive offices. A communication received from an interested party or unitholder will be promptly forwarded to the director or directors to whom the communication is addressed. A copy of the communication will also be provided to our president and chief executive officer. We will not, however, forward sales or marketing materials or correspondence primarily commercial in nature or not clearly identified as interested party or unitholder correspondence.
Directors and Executive Officers
The following table sets forth the members of the Board of Directors and Audit Committee and the executive officers of our general partner. There are no family relationships between any of our executive officers or members of the Board of Directors and the Audit Committee. Some of these individuals are also officers of certain of our subsidiaries or affiliates.
Name
Age
Position
David L. Kyle
Chairman, Board of Directors
John W. Gibson
President and Chief Executive Officer,
Member, Board of Directors,
Member, Northern Border Management Committee
Jim Kneale
President and Chief Operating Officer, ONEOK, Inc.
Member, Board of Directors
Curtis L. Dinan
Senior Vice President, Chief Financial Officer and
Treasurer
Jerry L. Peters
Senior Vice President and Chief Accounting Officer
John R. Barker
Executive Vice President, General Counsel and Secretary
Gary N. Petersen
Member, Board of Directors and Audit Committee
Gerald B. Smith
Member, Board of Directors and Chairman, Audit
Committee
Gil J. Van Lunsen
Member, Board of Directors and Audit Committee
David L. Kyle was named chairman of the board of directors of ONEOK Partners GP effective January 1, 2007. From May 2006 through December 2006 he served as chairman and chief executive officer of ONEOK Partners GP. He was named chairman of our former Partnership Policy Committee and was designated a member of the Northern Border Management Committee in 2004. Mr. Kyle is also the chairman of ONEOK. He was employed by Oklahoma Natural Gas Company in 1974 as an engineer trainee. He served in a number of positions prior to being elected vice president of gas supply in 1986 and executive vice president in 1990. He was named president of Oklahoma Natural Gas Company in 1994. He was named president of ONEOK in 1997, and named chairman of the board and appointed the chief executive officer of ONEOK in 2000. Mr. Kyle is a member of the board of directors of Bank of Oklahoma Financial Corporation.
John W. Gibson became our president and chief executive officer effective January 1, 2007. He served as our president and chief operating officer from May through December 2006. He was designated a member of the Northern Border Management Committee in 2006. From 2005 until May 2006 he was president of ONEOK Energy Companies, which included ONEOK’s gathering and processing, natural gas liquids, pipelines and storage and energy services business segments, some of which were acquired by us in April 2006. Prior to that, he was president, Energy, from 2000 to 2005 for ONEOK.
Jim Kneale became the president and chief operating officer of ONEOK effective January 1, 2007. He served as our executive vice president and chief financial officer from May through December 2006. From 1999 to 2000 he was vice president, treasurer and chief financial officer and from 2001 to 2004 senior vice president, treasurer and chief financial officer for ONEOK. From 2005 through May 2006, he was executive vice president, finance and administration and chief financial officer for ONEOK.
Curtis L. Dinan became our senior vice president, chief financial officer and treasurer effective January 1, 2007. Mr. Dinan served as senior vice president and chief accounting officer of ONEOK from August 2004 through December 2006 and served as vice president and chief accounting officer of ONEOK from February 2004 to August 2004. Prior to joining ONEOK in February 2004, Mr. Dinan served as an assurance and business advisory partner at Grant Thornton, LLP from 2002 to 2004. He served as an assurance and business advisory partner at Arthur Andersen, LLP from 2001 to 2002.
Jerry L. Peters was named our senior vice president and chief accounting officer effective January 1, 2007. From May through December 2006, Mr. Peters served as senior vice president, chief accounting officer and treasurer. Mr. Peters served
as our chief financial and accounting officer from 1994 to May 2006. Mr. Peters was vice president, finance of the following former affiliates of ONEOK Partners GP: Florida Gas Transmission Company from February 2001 to May 2002; Transportation Trading Services Company from September 2001 to July 2002; Citrus Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from November 2001 to May 2002. Prior to joining ONEOK Partners GP in 1985, Mr. Peters was employed by KPMG LLP as a certified public accountant.
John R. Barker became our executive vice president, general counsel and secretary in May 2006. Mr. Barker is also senior vice president, general counsel and assistant secretary for ONEOK, having been appointed to that position in 2004. From 1994 to 2004, he was a stockholder, president and director of Gable & Gotwals, a law firm located in Tulsa, Oklahoma, which provides legal services to both us and ONEOK.
Gary N. Petersen was appointed to the Audit Committee in 2002. Since 1998, he has provided consulting services related to strategic and financial planning. Additionally, he is president of Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant Energy-Minnegasco. He served as president and chief operating officer of Reliant Energy-Minnegasco from 1991 to 1998. Prior to his employment at Minnegasco, he was a senior auditor with Arthur Andersen. He currently serves on the boards of the YMCA of Metropolitan Minneapolis and the Dunwoody College of Technology.
Gerald B. Smith was appointed to the Audit Committee in 1994. He is chairman and chief executive officer and co-founder of Smith, Graham & Company Investment Advisors, a global investment management firm, which was founded in 1990. He is a member of the board of trustees of the Charles Schwab Family of Funds and a director and member of the Cooper Industries audit committee. He is a former director of the Fund Management Board of Robeco Group, Rorento N.V. (Netherlands).
Gil J. Van Lunsen was appointed to the Audit Committee in March 2005. Prior to his retirement in 2000, Mr. Van Lunsen was a managing partner of KPMG LLP at the firm’s Tulsa, Oklahoma office. He began his career with KPMG LLP in 1968. He is currently a director and audit committee chairman of Array Biopharma in Boulder, Colorado, and Sirenza Microdevices in Broomfield, Colorado.
Director Compensation
Compensation for our non-management directors for the year ended December 31, 2006 consisted of an annual cash retainer of $40,000 and meeting fees of $1,500 for each Board of Director or Audit Committee meeting attended in person or $750 for each Board of Director or Audit Committee meeting attended by telephone. In addition, the chair of our Audit Committee received an additional annual cash retainer of $10,000. Non-management directors are reimbursed for their expenses related to their attendance at Board of Director and Audit Committee meetings. A director who is also an officer or employee of ONEOK Partners GP or ONEOK receives no compensation for his or her service as a director. During 2006, the chair of our Audit Committee received additional compensation in the amount of $80,000 and the remaining two members of our Audit Committee each received additional compensation in the amount of $65,000 for their service in reviewing the ONEOK Transactions.
We are required to indemnify the members of the Board of Directors and the general partner, its affiliates and its respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than the general partner) not opposed to, our best interests and, with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful.
The following table sets forth the compensation paid to our non-management directors in 2006.
2006 DIRECTOR COMPENSATION
Compensation Committee Interlocks and Insider Participation
We do not have a compensation committee. During 2006, the compensation of our named executive officers was determined by ONEOK’s Executive Compensation Committee, which consists of independent members of the ONEOK Board of Directors. No member of ONEOK’s Executive Compensation Committee is, or was formerly, an officer, director or employee of ONEOK Partners or any if its subsidiaries.
Governance Matters
Audit Committee Independence - Our Board of Directors has a standing Audit Committee. Our guidelines for determining the independence of members of the Audit Committee are included in our Governance Guidelines. Our Governance Guidelines provide that the members of the Audit Committee shall at all times qualify as independent under the listing standards of the NYSE and the applicable rules of the SEC and other applicable laws. At least annually the Board of Directors reviews the relationships of each Audit Committee member with us to affirmatively determine the independence of each member. In January 2007, our Board of Directors affirmatively determined that Mr. Petersen, Mr. Smith, and Mr. Van Lunsen meet the standards for independence set forth in the Governance Guidelines and are therefore independent.
Audit Committee Financial Experts - Annually, our Board of Directors reviews the financial expertise of the members of our Audit Committee. In January 2007, our Board of Directors determined that Mr. Petersen, Mr. Smith and Mr. Van Lunsen are each an “audit committee financial expert,” as defined by the rules of the SEC.
Executive Sessions of Board and Audit Committee - Our Board of Directors has documented its governance practices in our Governance Guidelines. The Board of Directors of our general partner holds regular executive sessions in which non-management board members meet without any members of management present. The chairman of our Audit Committee, Mr. Smith, presides at regular sessions of the non-management members of our Board of Directors. Meetings of the non-management board and committee members are scheduled quarterly or as requested by any non-management member.
Service on Other Audit Committees - Mr. Smith serves on the audit committee of one other public company. Mr. Van Lunsen serves on the audit committees of two other public companies. The Board of Directors has determined that Mr. Smith’s and Mr. Van Lunsen’s service on these other audit committees does not impair their ability to effectively serve on our Audit Committee.
Section 16(a) Beneficial Ownership Reporting Compliance - Section 16(a) of the Exchange Act requires executive officers, members of the Board of Directors and persons who own more than 10 percent of our common units to file reports of ownership and changes in ownership with the SEC and the NYSE and to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms received by us during and with respect to the 2006 fiscal year, or written representations from certain reporting persons that no Form 5s were required for those persons, we believe that during 2006 our reporting persons complied with all applicable filing requirements in a timely manner.
Governance Guidelines - The Board of Directors of our general partner has adopted our Governance Guidelines that address several governance matters, including responsibilities of directors, the composition and responsibility of the Audit Committee, the conduct and frequency of board meetings, management succession, director access to management and outside advisors, director orientation and continuing education, and annual self-evaluation of the board. The Board of Directors of our general
partner recognizes that effective governance is an on-going process, and thus, the Board of Directors will review our Governance Guidelines periodically as deemed necessary.
Code of Ethics - The Board of Directors of our general partner has adopted an Accounting and Financial Reporting Code of Ethics applicable to our chief executive officer, chief financial officer and chief accounting officer. In addition to other maters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code. We intend to post on our website any amendment to, or waiver from, any provision of our Accounting and Financial Reporting Code of Ethics within four business days following such amendment or waiver, in accordance with the applicable rules of the SEC and NYSE.
Code of Conduct - The Board of Directors of our general partner has adopted a Code of Conduct applicable to the members of our Board of Directors and Audit Committee, our officers and the employees of ONEOK, ONEOK Partners GP, and ONEOK Services Company, who provide services to us. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code. We intend to promptly post on our website any amendments to, or waivers from (including any implicit waiver), any provision of our Code of Conduct according to the rules of the SEC and NYSE.
Web Access - We provide access through our website at www.oneokpartners.com to current information relating to our governance, including our Audit Committee Charter, our Accounting and Financial Reporting Code of Ethics, our Code of Conduct, our Governance Guidelines and other matters impacting our governance principles. You may copy each of these documents from our website and you may also contact the office of the secretary of our general partner for printed copies of these documents free of charge.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, ONEOK Partners GP, the executive officers of which are employees of ONEOK. Certain officers of ONEOK Partners GP are deemed to be executive officers of us. Our reimbursement to ONEOK for a portion of the total compensation paid to the executive officers of our general partner is governed by our Services Agreement with ONEOK. Please read “Certain Relationships and Related Party Transactions, and Director Independence - Services Agreement” for a description of the Services Agreement.
We do not have a compensation committee. The compensation of the officers of our general partner, who are deemed to be our officers, is set by the Executive Compensation Committee of the Board of Directors of ONEOK. A discussion of the objectives of, and other matters related to, ONEOK’s compensation programs is included in ONEOK’s compensation discussion and analysis and other disclosure related to ONEOK executive compensation contained in ONEOK’s 2007 Proxy Statement as filed with the SEC (ONEOK 2007 Proxy Statement), a copy of which is provided on, and may be copied from, ONEOK’s website at www.oneok.com and is available free of charge from the secretary of ONEOK Partners GP upon request.
Under our Services Agreement with ONEOK, a portion of the compensation expense for our named executive officers is allocated by ONEOK to us. The compensation amounts shown in the following table are that portion of the named executive officer’s total compensation which is allocated to and paid by us under the Services Agreement.
The following table summarizes the compensation allocated to and paid by us in 2006 for our principal executive officer, principal financial officer and the three other most highly compensated executive officers of our general partner, ONEOK Partners GP, which we collectively refer to as the “named executive officers.”
Summary Compensation Table For 2006
(1) The amounts included in the table reflect the expense allocated to and recognized by us in 2006 for restricted stock, restricted stock incentive units and performance units granted under the ONEOK Long-Term Incentive Plan (LTI Plan) and the ONEOK Equity Compensation Plan, the value of which was determined in accordance with Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments,” (Statement 123R). Assumptions used in the calculation of the value of these equity grants are included in Note P to the ONEOK audited financial statements for the year ended December 31, 2006, included in the ONEOK 2006 Annual Report on Form 10-K filed with the SEC on February 28, 2007.
Restricted stock and restricted stock incentive units vest three years from the date of grant. Because no shares of ONEOK common stock are issued under a restricted stock incentive unit until the unit vests, no dividends are payable with respect to restricted stock incentive units. The performance units vest three years from the date of grant at which time the holder is entitled to receive a percentage (0 percent to 200 percent in increments of 50 percent) of the performance units granted based on ONEOK total shareholder return over the performance cycle compared to the total shareholder return of a peer group of 20 other energy companies. Grants of restricted stock, restricted stock incentive units and performance units made in 2003 and 2006 are payable in shares of ONEOK common stock upon vesting. Grants of restricted stock incentive units and performance units made in 2004 and 2005 are payable one-third in cash and two-thirds in shares upon vesting. The fair value of restricted stock and restricted stock incentive units for the purposes of Statement 123R was determined on the date of grant based on the closing stock price of ONEOK common stock on the grant date adjusted for the current dividend yield. The fair value of the performance units granted in 2003, 2004 and 2005 for the purposes of Statement 123R was determined on the date of grant based on the closing stock price of ONEOK common stock on the grant date adjusted for the current dividend yield. With respect to the performance units granted in 2006, the fair value for the purposes of Statement 123R was determined using a valuation model that considers the market condition (total shareholder return), using assumptions developed from historical information of ONEOK and a group of 20 peer companies of ONEOK.
(2) No options were granted by ONEOK in 2006 except for restored options granted in connection with the exercise of options granted under the LTI Plan. Effective January 1, 2007, the restorative feature of all outstanding ONEOK stock options was eliminated. The 2003 option grant vested on February 20, 2006. The amounts included in the table reflect our allocated portion of the value of the 2003 grant and the restored options granted in 2006 as expensed in accordance with Statement 123R. Assumptions used in the calculation of the value of option grants are included in Note P to the ONEOK audited financial statements for the year ended December 31, 2006, included in the ONEOK 2006 Annual Report on Form 10-K filed with the SEC on February 28, 2007.
(3) Reflects the amounts allocated to and paid by us under the ONEOK 2006 annual officer incentive plan. The plan provides that ONEOK officers may receive annual cash incentive awards based on the performance and profitability of ONEOK, the performance of particular business units of ONEOK, and individual performance. The corporate and business unit criteria and individual performance criteria are established annually by the ONEOK Executive Compensation Committee of the ONEOK Board of Directors.
The Committee also establishes annual target awards for each ONEOK officer. For a discussion of the performance criteria established by the ONEOK Executive Compensation Committee for awards under the 2006 annual officer incentive plan, see “Components of Compensation - Annual Cash Compensation” in the ONEOK 2007 Proxy Statement.
(4) Reflects the portion of the aggregate current year change in pension values and above market earnings on nonqualified deferred compensation allocated to us for each named executive officer. The change in pension values is based on the change of the present value of the benefit. For a discussion of the ONEOK pension plan, see the ONEOK 2007 Proxy Statement. The present value is based on the earliest age for which an unreduced benefit is available (age 62) and assumptions from the September 30, 2006 and 2005 financial reporting dates for the ONEOK pension plan.
Our allocated portion of above market earnings on nonqualified deferred compensation was $671 for Mr. Kyle and $394 for Mr. Kneale. For additional information on the ONEOK Nonqualified Deferred Compensation Plan, see “Long-Term Compensation Plans - Nonqualified Deferred Compensation Plan” in the ONEOK 2007 Proxy Statement.
(5) Reflects the portion allocated to us of the amounts paid as ONEOK’s match under the ONEOK Employee Nonqualified Deferred Compensation Plan, amounts paid as ONEOK’s match under the Thrift Plan for Employees of ONEOK; amounts paid as tax reimbursements for employee stock awards under the ONEOK Employee Stock Award Program; amounts expensed in accordance with Statement 123R for shares issued under the ONEOK Employee Stock Award Program; amounts paid for relocation expenses; and amounts paid as employee service awards, as follows:
(a) This amount was awarded Mr. Kneale for 25 years of service to ONEOK.
The thrift plan for employees of ONEOK, Inc. is a tax qualified plan which covers substantially all ONEOK employees. Employee contributions are discretionary. Subject to certain limits, ONEOK matches employee contributions to the plan up to a maximum of 6 percent.
For additional information on the ONEOK Nonqualified Deferred Compensation Plan, see “Long-Term Compensation Plans - Nonqualified Deferred Compensation Plan” in the ONEOK 2007 Proxy.
Under the ONEOK Employee Stock Award Program, ONEOK issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of ONEOK common stock when the closing price of ONEOK common stock on the NYSE was for the first time at or above $26 per share. Nine shares were issued to each named executive officer under this program in 2006.
Other than as set forth above, the named executive officers did not receive perquisites or other personal benefits with an aggregate value of $10,000 or more.
(6) Effective January 1, 2007, Mr. Kyle became our chairman of the board, Mr. Gibson became our president and chief executive officer, and Mr. Kneale became the president and chief operating officer ONEOK, Inc.
(7) Mr. Cordes served as our chief executive officer until May 2006.
(8) Mr. Peters served as our chief financial and accounting officer until May 2006.
Partnership Phantom Unit Plan
Effective November 1, 2001, Northern Plains and NBP Services adopted the Amended and Restated Northern Border Phantom Unit Plan as an incentive to attract and retain employees who are essential to the services provided to us and our subsidiaries. By its terms, the Amended and Restated Northern Border Phantom Unit Plan terminated on December 31, 2004. The Administrative Committee under the plan, which consists of appointees of ONEOK Partners GP and ONEOK Services Company, will continue to administer the outstanding phantom units. The Administrative Committee has complete authority to determine the time and provisions for settlement of the phantom units. During the duration of a grant, the participant’s account is credited with distributions paid, which are based upon the general partner distribution rate, with respect to the underlying security. Upon settlement of the phantom units, the participant will receive common units, cash or a combination
thereof, as determined by the Administrative Committee. The settlement value of the phantom units is determined by using a value derived from the general partner distribution rate and common unit distribution yield on the settlement date.
The following table sets forth the outstanding phantom units held by the named executive officers at December 31, 2006.
Outstanding Equity Awards at December 31, 2006
The following table sets forth the phantom units which vested during 2006 for each of the named executive officers.
Option Exercises and Stock Vested in 2006
Potential Post-Employment Payments and Payments upon a Change in Control
Severance Plans - ONEOK Partners GP and NBP Services Severance Pay Plans provide for the payment of benefits to employees who are terminated due to reorganization or similar business circumstances. There are no severance benefits for performance related terminations. For those terminated as the result of reorganization or similar business circumstances, the benefit is based on length of service and amount of pay with a minimum benefit of eight weeks of base pay up to a maximum payment of 52 weeks of base pay. The employee must sign a waiver and release of claims agreement in order to receive any severance benefit.
Payments Made Upon Any Termination - Regardless of the manner in which a named executive officer’s employment terminates, he is entitled to receive amounts earned during his term of employment. Such amounts include:
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accrued but unpaid salary;
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amounts contributed under the ONEOK Thrift Plan and the ONEOK Employee Nonqualified Deferred Compensation Plan; and
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amounts accrued and vested through the ONEOK retirement plan and supplemental executive retirement plan (SERP).
Payments Made Upon Retirement - In the event of the retirement of a named executive officer, in addition to the items identified above, such named executive officer will:
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be entitled to certain exercise rights with respect to each outstanding and vested stock option granted under the ONEOK LTI Plan;
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be entitled to receive a prorated portion of each outstanding performance unit granted under the ONEOK LTI Plan and Equity Compensation Plan upon the completion of the performance cycle;
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be entitled to receive a prorated portion of each outstanding restricted stock incentive unit granted under the ONEOK LTI Plan and Equity Compensation Plan upon completion of the restricted cycle;
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if eligible, continue to receive ONEOK health and welfare benefits and receive ONEOK health and welfare benefits for his dependents, as applicable; and
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if eligible, continue to receive ONEOK life insurance benefits until death.
Payments Made Upon Death or Disability - In the event of the death or disability of a named executive officer, in addition to the benefits listed under the headings “Payments Made Upon Any Termination” and “Payments Made Upon Retirement” above, the named executive officer will receive benefits under ONEOK’s disability plan or payments under ONEOK’s life insurance plan, as appropriate.
Payments Made Upon a Change in Control - Effective January 2005, ONEOK entered into amended and restated termination agreements with each of our named executive officers. Each termination agreement has an initial two-year term from the date the agreement was entered into and is automatically extended in one-year increments after the expiration of the initial term unless ONEOK provides notice of non-renewal to the officer, or the officer provides notice of non-renewal to ONEOK, at least 90 days before the January 1 preceding any termination date of the agreement. If a “change in control” of ONEOK occurs, the term of each termination agreement will not expire for at least three years after the change in control.
Effective December 21, 2006, ONEOK’s termination agreement with Mr. Kyle was terminated by mutual agreement as a result of the change in Mr. Kyle’s position with ONEOK. Also, effective December 21, 2006, ONEOK entered into an amended and restated termination agreement with Mr. Gibson which provides for an initial term through January 1, 2008, and is thereafter automatically extended on an annual basis until either party gives written notice of its election to terminate the agreement 90 days following the date of such notice.
Under the termination agreements, all change in control benefits are “double trigger.” Payments and benefits under these termination agreements are payable if the officer’s employment is terminated by ONEOK without “just cause” or by the officer for “good reason” at any time during the three years following a change in control. In general, severance payments and benefits include a lump sum payment in an amount equal to the sum of (1) for Messrs. Cordes, Gibson, Kneale and Skoog, three times, and for Messrs. Norton and Peters, two times, the aggregate of the officer’s annual salary as then in effect, plus the greater of either the amount of the officer’s bonus received in the prior year or the officer’s target bonus for the then current period, and (2) a prorated portion of the officer’s target short-term incentive compensation. Messrs. Cordes, Gibson, Kneale, and Skoog would also be entitled to continuation of health and welfare benefits for 36 months and accelerated benefits under the ONEOK SERP. Messrs. Norton and Peters would be entitled to continuation of health and welfare benefits for 24 months. In the case of Messrs. Gibson and Kneale, ONEOK will make gross up payments to them to cover any excise taxes due if any portion of their severance payments constitutes an excess parachute payment. ONEOK will make gross up payments to such officers only if the severance payments, as reduced, are subsequently deemed to constitute excess parachute payments. For Messrs. Cordes, Norton, Peters and Skoog, severance payments will be reduced if the net after-tax benefit to such named executive officer exceeds the net after-tax benefit if such reduction were not made.
For the purposes of these agreements, a “change in control” generally means any of the following events:
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an acquisition of ONEOK voting securities by any person that results in the person having beneficial ownership of 20 percent or more of the combined voting power of ONEOK’s outstanding voting securities, other than an acquisition directly from ONEOK;
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the current members of the ONEOK Board, and any new director approved by a vote of at least two-thirds of the ONEOK Board, cease for any reason to constitute at least a majority of the ONEOK Board, other than in connection with an actual or threatened proxy contest (collectively, the “Incumbent Board”);
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a merger, consolidation or reorganization with ONEOK or in which ONEOK issues securities, unless (a) ONEOK’s shareholders immediately before the transaction, as a result of the transaction, own, directly or indirectly, at least 50 percent of the combined voting power of the voting securities of ONEOK resulting from the transaction, (b) the members of the ONEOK Incumbent Board after the execution of the transaction agreement constitute at least a majority of the members of the Board of ONEOK resulting from the transaction, or (c) no person other than persons who, immediately before the transaction owned 30 percent or more of ONEOK’s outstanding voting securities, has beneficial ownership of 30 percent or more of the outstanding voting securities of ONEOK resulting from the transaction; or
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ONEOK completes the liquidation or dissolution or the sale or other disposition of all or substantially all of ONEOK’s assets.
For the purposes of these agreements, “just cause” means the executive’s conviction in a court of law of a felony, or any crime or offense in a court of law of a felony, or any crime or offense involving misuse or misappropriation of money or property; the executive’s violation of any covenant, agreement or obligation not to disclose confidential information regarding our business; any violation by the executive of any covenant not to compete with us; any act of dishonesty by the executive which adversely affects our business; any willful or intentional act of the executive which adversely affects our business, or reflects unfavorably on our reputation; the executive’s use of alcohol or drugs which interferes with the executive’s performance of duties as our employee; or the executive’s failure or refusal to perform the specific directives of our Board of Directors or its officers, which directives are consistent with the scope and nature of the executive’s duties and responsibilities. The existence and occurrence of all of such causes are to be determined by us, in our sole discretion, provided, that nothing contained in these provisions of these agreements are to be deemed to interfere in any way with our right to terminate the executive’s employment at any time without cause.
For the purposes of these agreements, “good reason” means a demotion, loss of title or significant authority or responsibility of the executive with respect to the executive’s employment with us from those in effect on the date of a change in control, a reduction of salary of the executive from that received from us immediately prior to the date of a change in control, a reduction in short-term and/or long-term incentive targets from those applicable to the executive immediately prior to the date of a change in control, the relocation of our principal executive offices to a location outside the metropolitan area of Tulsa, Oklahoma, or our requiring a relocation of principal place of employment of the executive, or the failure of a successor corporation to explicitly assume this termination agreement.
The following tables reflect estimates of the amount of incremental compensation due to each named executive officer in the event of such executive’s termination of employment upon death, disability or retirement, termination of employment without cause or termination of employment following a change in control. The amounts shown assume that such termination was effective as of December 31, 2006, and are estimates of the amounts which would be paid out to the executives upon such termination. The actual amounts to be paid out can only be determined at the time of such executive’s separation from the Partnership.
In addition to the amounts set forth in the following tables, in the event of termination of employment for any of the reasons set forth in the tables, each of the named executive officers would receive the following payments or benefits: David L. Kyle, $1,126,153 in exercisable options, $2,852,684 in pension and SERP benefits, and $1,186,593 in nonqualified deferred compensation; John W. Gibson, $1,142,364 in exercisable options, $1,803,128 in pension and SERP benefits, and $322,159 in nonqualified deferred compensation; William R. Cordes, $274,526 in pension and SERP benefits, and $91,949 in nonqualified deferred compensation; Christopher R Skoog, $522,679 in exercisable options, $738,483 in pension and SERP benefits, and $554,495 in nonqualified deferred compensation; Jim Kneale, $136,436 in exercisable options, $1,229,774 in pension and SERP benefits, and $373,781 in nonqualified deferred compensation; Pierce H. Norton, $49,570 in pension and SERP benefits; and Jerry Peters, $51,928 in pension and SERP benefits, and $16,237 in nonqualified deferred compensation.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Beneficial Ownership
The following table sets forth the beneficial ownership of our common units and the common stock of ONEOK, the parent company of our general partner, as of February 1, 2007, by each named executive officer, each member of our Board of Directors of our general partner, and all executive officers and members of our Board of Directors as a group. Other than as set forth below, no person is known to us to beneficially own more than five percent of our common units.
The following table sets forth the equity compensation plan information at December 31, 2006.
Equity Compensation Plan Information
(1) Under our partnership agreement, the Board of Directors of ONEOK Partners GP has the sole authority to adopt employee benefit or incentive plans or issue common units pursuant to any employee benefit or incentive plan maintained or sponsored by the general partner or its affiliates.
(2) Based on the closing price of the common units on December 31, 2006, assuming that all outstanding phantom units were settled in common units as of December 31, 2006.
(3) The plan limits the number of grants of phantom units and phantom LP units to an aggregate of 200,000. This assumes all grants are phantom LP units.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Related-Person Transactions
Our Board of Directors recognizes that transactions between us and related persons (ONEOK and its subsidiaries, affiliates and their and our executive officers, directors, and their immediate family members) can present potential or actual conflicts of interest and create the appearance our decisions are based on considerations other than our best interests and our unitholders. Accordingly, as a general matter, it is our preference to avoid related person transactions. Nevertheless, we recognize that there are situations where related person transactions may be in, or may not be inconsistent with, our best interests and our unitholders including, but not limited to, situations where we acquire products or services from related persons on an arm’s length basis on terms comparable to those provided to unrelated third parties.
In the event we enter into a transaction in which ONEOK or its subsidiaries or affiliates or their or our executive officers (other than an employment relationship), directors, or a members of their immediate family have a direct or indirect material interest, the transaction is presented to our Audit Committee and, if warranted, our Board of Directors for review, to determine if the transaction creates a conflict of interest and is otherwise fair to us. We require each executive officer and director of our general partner to annually provide us written disclosure of any transaction between the officer or director and us. Our Board of Directors reviews this disclosure in connection with its annual review of the independence of our Audit Committee. These procedures are not in writing but are evidenced through the meeting agendas of our Board of Directors and our Audit Committee.
The ONEOK Transactions
As part of the ONEOK Transactions, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. As a result, ONEOK now owns our entire 2 percent general partner interest.
We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited units, which, when combined with its general partner interest, increases its total interest in us to approximately 45.7 percent.
Prior to the April 2006 acquisition, the balance sheet of the ONEOK Energy Assets included long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was retained by ONEOK as part of the ONEOK Transactions.
In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline and an affiliate of TransCanada will become the operator of the pipeline in April 2007.
As provided in our Partnership Agreement, our Audit Committee engaged independent legal counsel and an independent financial advisor to assist in the Audit Committee’s review of these transactions. Following its review, the Audit Committee determined that these transactions were fair and reasonable to us and our unitholders. Additional information about the ONEOK Transactions is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under “Recent Developments.”
Relationship with ONEOK
ONEOK owns our sole general partner, ONEOK Partners GP, and is able to elect members of our Board of Directors and our Audit Committee. Other relationships include the following.
Cash Distributions - ONEOK owns approximately 0.5 million of our common units and approximately 36.5 million of our Class B limited units, which, when combined with its general partner interest, represents an approximate 45.7 percent interest in us. For 2006, we declared total cash distributions to ONEOK of $145.1 million, which included $31.1 million related to its incentive distribution rights. Additional information about our cash distribution policy is included in Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Services Agreement - In April 2006, we entered into a Services Agreement with ONEOK, ONEOK Partners GP and NBP Services that replaced the Administrative Services Agreement between us and NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK will provide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement.
ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financing services, employee benefits provided through ONEOK’s benefit plans, administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees. However, an expense benefiting the consolidated company but have no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and wages. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.
In 2006, the aggregate amount charged by ONEOK, NBP Services and their affiliates to us for their services was approximately $105.7 million.
Operating and Administrative Services Agreements - ONEOK Partners GP provides certain administrative, operating and management services to us and Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas Transmission and Guardian Pipeline through operating agreements. We and Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission are charged for the salaries, benefits and expenses of ONEOK Partners GP incurred in connection with the operating agreements.
Transportation Agreements - ONEOK Energy Services, a subsidiary of ONEOK, became an affiliate of Northern Border Pipeline in November 2004 in connection with ONEOK’s purchase of ONEOK Partners GP. In 2006, 2 percent of Northern Border Pipeline’s design capacity was contracted on a firm basis with ONEOK Energy Services. Revenue from ONEOK Energy Services for 2006 was $7.0 million. As of January 31, 2007, 1 percent of Northern Border Pipeline’s design capacity was contracted on a firm basis with ONEOK Energy Services for 2007.
Our Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A significant portion of our Pipelines and Storage segment’s revenues are from ONEOK and its subsidiaries, which utilize both transportation and storage services. Our Interstate Natural Gas Pipelines segment provides transportation services to ONEOK and its subsidiaries.
Bushton Plant - As part of the ONEOK Transactions, we acquired contractual rights to process natural gas at the Bushton Plant that is leased by OBPI. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides processing and related services at the Bushton Plant through 2012. In exchange for such services, we pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of OBPI’s obligations under equipment leases covering the Bushton Plant. On January 1, 2007, the Bushton Plant was temporarily idled. We are in the process of adding new facilities and making other changes at the Bushton Plant as part of our Overland Pass Pipeline project and associated expansions.
Derivative Contracts - An affiliate of ONEOK from time to time enters into commodity derivative contracts on behalf of our Gathering and Processing segment. See Note G for a discussion of our derivative instruments and hedging activities.
Relationship with TransCanada
As part of the ONEOK Transactions, in April 2006 ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. In 2006, we declared total cash distributions to TransCanada of $0.7 million, which included $0.5 million related to its incentive distribution rights. Additional information about our cash distribution policy is included in Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
ONEOK Partners GP and TransCanada’s affiliate that will become the operator of Northern Border Pipeline entered into a transition services agreement for the transfer of the operator function effective April 1, 2007. Northern Border Pipeline agreed to pay ONEOK Partners GP an amount up to $1.0 million per year for years 2007 through 2011, to reimburse ONEOK Partners GP for shared equipment and furnishings acquired by ONEOK Partners GP and used to support Northern Border Pipeline operations.
Conflicts of Interest
Our Board of Directors, whose members are designated by our general partner, ONEOK Partners GP, establishes our business policies.
Our general partner, which is a subsidiary of ONEOK, and its respective affiliates currently engage or may engage in the businesses in which we engage or in which we may engage in the future. As a result, conflicts of interest may arise between our general partner and its affiliates, and us. If such conflicts arise, the members of our Board of Directors generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest.
TC PipeLines (a 50 percent owner of Northern Border Pipeline) and its affiliates are also engaged in interstate natural gas pipeline transportation in the United States separate from their interest in Northern Border Pipeline. As a result, conflicts also may arise between TransCanada and its affiliates or TC PipeLines and its affiliates, and Northern Border Pipeline. If such conflicts arise, the representatives on the Northern Border Management Committee generally have a fiduciary duty to resolve such conflicts in a manner that is in the best interest of Northern Border Pipeline.
Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally require a general partner of a partnership to adhere to fiduciary duty standards under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on our general partner’s Board of Directors or the Northern Border Management Committee. Because of the competing interests identified above, our Partnership Agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these fiduciary duties. For example:
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Our Partnership Agreement states that our general partner, its affiliates and their officers and directors will not be liable for damages to us, our limited partners or their assignees for errors of judgment or for any acts or omissions if the general partner and such other persons acted in good faith.
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Our Partnership Agreement allows our general partner and our Board of Directors to take into account the interests of other parties in addition to our interests in resolving conflicts of interest.
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Our Partnership Agreement provides that our general partner will not be in breach of its obligations under our Partnership Agreement or its duties to us or our unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in our partnership agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might otherwise be a breach of fiduciary duty.
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Our Partnership Agreement provides that a purchaser of common units is deemed to have consented to certain conflicts of interest and actions of our general partner and its affiliates that might otherwise be
prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partner of any duty stated or implied by law or equity.
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The Audit Committee of our general partner will, at the request of the general partner or a member of our Board of Directors, review conflicts of interest that may arise between a general partner and its affiliates (or the member of our Board of Directors designated by it), and the unitholders or us. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us.
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The Partnership Agreement of Northern Border Pipeline relieves us and TC PipeLines, our affiliates and transferees from any duty to offer business opportunities to Northern Border Pipeline, subject to specified exceptions.
We are required to indemnify the general partner, the members of its Board of Directors, and its affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The fees for the years ended December 31, 2006, and 2005 for professional services provided by KPMG LLP were as follows:
Audit Fees
Audit fees include fees for the audit of our annual financial statements and internal control over financial reporting, reviews of our quarterly financial statements and related consents and comfort letters for documents filed with the SEC.
Audit Committee Policies and Procedures for Pre-Approval of Audit and Non-Audit Services
Consistent with SEC policies regarding auditor independence, the Audit Committee is responsible for pre-approving all audit and non-audit services performed by the independent auditor. In addition to its approval of the audit engagement, the Audit Committee takes action at least annually to authorize the performance by the independent auditor of several specific types of services within the categories of audit services, audit-related services, tax services and all other services. Audit services include assurance and related services that are reasonably related to the performance of the audit or review of the financial statements, attestations pursuant to Section 404 of the Sarbanes-Oxley Act, quarterly reviews, comfort letters, consents, review of registration statements, accounting research related to completed transactions and tax assistance related to the audit services. Audit-related services include due diligence related to potential business acquisitions/dispositions, accounting research and other audit or attest services. Authorized tax services include compliance-related services such as services involving tax filings, as well as consulting services such as tax planning, transaction analysis and opinions. All other services include special investigations to assist the Audit Committee or its counsel and assistance with regulatory activities. Services are subject to pre-approval of the specific engagement if they are outside the specific types of services included in the periodic approvals covering service categories or if they are in excess of specified fee limitations. The Audit Committee has delegated pre-approval authority to the Audit Committee chairman.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Exhibits
(3) Financial Statement Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ONEOK Partners, L.P.
By: ONEOK Partners GP, L.L.C., its General Partner
Date: February 28, 2007
By:
/s/ Curtis L. Dinan
Curtis L. Dinan
Senior Vice President,
Chief Financial Officer and Treasurer
(Signing on behalf of the Registrant
and as Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 28th day of February 2007.