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ONEOK Partners LP 10-K 2011 UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K>
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010.
OR
__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission file number 1-12202
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes X No __
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer X Accelerated filer __ Non-accelerated filer __ Smaller reporting company __
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X.
Aggregate market value of the common units held by non-affiliates based on the closing trade price on June 30, 2010, was $4.2 billion.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
DOCUMENTS INCORPORATED BY REFERENCE: >None.
As used in this Annual Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, and “Forward-Looking Statements,” in this Annual Report.
PART I
ITEM 1. BUSINESS>
ONEOK Partners, L.P. is a publicly traded Delaware master limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.” We are one of the largest publicly traded master limited partnerships and a leader in the gathering, processing, storage and transportation of natural gas in the United States. In addition, we own one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.
DESCRIPTION OF BUSINESS
We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP, which consists of 10 members. Seven of our Board members qualify as independent under the listing standards of the NYSE and also serve as the Audit Committee of ONEOK Partners GP. Four of our independent directors serve on the Conflicts Committee.
ONEOK Partners GP is a wholly owned subsidiary of ONEOK. Three of our Board members who are independent under NYSE listing standards and one management member of our Board are also members of ONEOK’s Board of Directors. ONEOK and its subsidiaries own a 42.8-percent aggregate equity interest in us.
Our primary business strategy is to increase distributable cash flow through consistent and sustainable earnings growth while focusing on safe, reliable, environmentally responsible and legally compliant operations for our customers, employees, contractors and the public through the following:
Our 2010 operating results include the benefits from a full year of operation of more than $2.0 billion in growth projects completed in 2009, reflecting increases in volumes gathered, fractionated and sold in our Natural Gas Liquids segment, capacity contracted in our Natural Gas Pipelines segment and volumes processed in the Williston Basin in our Natural Gas Gathering and Processing segment. We expect continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas as drilling activities increase in these areas.
We announced approximately $1.8 billion to $2.1 billion in growth projects in 2010 and early 2011, primarily in the Williston Basin in North Dakota and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas that will enable us to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities.
Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of 2010. The development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics, with the associated natural gas production having a high NGL content. Current natural gas processing and natural gas liquids infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities. We have announced plans to invest $1.5 to $1.8 billion in the Williston Basin in North Dakota.
In addition to the growth projects in the Williston Basin, we have announced plans to invest approximately $270 million to $330 million in our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. The expansions and upgrades will increase our ability to accommodate the growing natural gas and NGL supply from producers and natural gas processors as drilling activities increase in these areas. These investments will expand our ability to transport raw NGLs from these supply areas to fractionation facilities in Kansas, Oklahoma and Texas and distribute purity NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. A portion of these investments will also allow us to increase utilization of our natural gas processing capacity in Oklahoma. During 2010, we paid cash distributions totaling $4.46 per unit, an increase of approximately 3.0 percent over the $4.33 per unit paid during 2009. In January 2011, our general partner declared a cash distribution of $1.14 per unit ($4.56 per unit on an annualized basis), an increase of approximately 3.6 percent over the $1.10 declared in January 2010.
During 2010, we utilized available cash, our Partnership Credit Agreement, our commercial paper program and the proceeds from the sale of a 49-percent ownership interest in Overland Pass Pipeline Company to fund our short-term liquidity needs, repay $250 million of maturing senior notes and fund our capital expenditures. Additionally, we accessed the public equity markets in February 2010, generating net proceeds of approximately $322.7 million for our long-term financing needs.
In January 2011, we completed an underwritten public offering of senior notes generating net proceeds of approximately $1.28 billion. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, as well as fund our capital expenditures.
See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, for information on our growth projects, results of operations, liquidity and capital resources.
SEGMENT FINANCIAL INFORMATION
NARRATIVE DESCRIPTION OF BUSINESS
Natural Gas Gathering and Processing
with our processing assets in central Oklahoma. We seek to restructure expiring contracts to mitigate commodity price exposure and improve profitability. We also seek to provide safe, reliable, efficient and consistent operations of our natural gas gathering and processing assets, while managing costs.
In the Mid-Continent region and the Williston Basin, unprocessed 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 to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is shipped to fractionators where, through the application of heat and pressure, the unfractionated NGL stream is separated into NGL products. Our natural gas and NGL products are sold to affiliates and a diverse customer base. Our natural gas processing operations primarily utilize field gas processing plants to extract NGLs and remove water vapor and other contaminants from the unprocessed natural gas stream. Field gas processing plants process natural gas gathered from multiple producing wells.
We generally gather and process natural gas under the following types of contracts.
Revenues of this segment are derived primarily from fee and POP contracts. We expect that our recently announced capital projects will provide additional revenues from fee and POP contracts when completed. We use derivative instruments to mitigate our sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes.
See Note K of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.
In the Mid-Continent region, our natural gas gathering and processing assets in the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas are well established. We anticipate continuing volumetric declines in most non-shale wells that supply our natural gas gathering and processing operations; however, we expect this to be more than offset by the increased drilling activity in the Cana-Woodford Shale area of Western Oklahoma, in which we have a substantial natural gas gathering and processing position.
In the Rocky Mountain region, our Williston Basin volumes are growing as drilling activity increases, primarily driven by producer development of Bakken Shale oil wells, which also produce natural gas containing significant amounts of NGLs; however, we have seen declines in gathered natural gas volumes in the Powder River Basin.
Demand - Demand for natural gas gathering and processing services is typically aligned with the production of natural gas. Our natural gas processing plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing operating parameters at certain plants, we can reduce, to some extent, the amount of ethane and propane recovered if prices or processing margins are unfavorable.
Commodity Prices - Crude oil, natural gas and NGL prices are volatile due to market conditions such as storage injection and withdrawal rates, available storage capacity and demand for our products by the petrochemical industry and other consumers. We are exposed to commodity price risk and the cost of natural gas transportation at various market locations as a result of receiving commodities through our POP contracts in exchange for our services. To a lesser extent, exposures arise from the gross processing spread with respect to our keep-whole contracts.
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 needed to meet the electricity-generation demand required to cool residential and commercial properties. 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 variability as automotive travel increases and as seasonal gasoline formulation standards are implemented. During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence processing decisions.
Competition - The natural gas gathering and processing business remains relatively fragmented despite significant consolidation in the industry. We compete for natural gas supplies with major integrated oil companies, independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated
marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions. The factors that typically affect our ability to compete for natural gas supplies are:
We are responding to these industry conditions by making capital investments to construct and expand our assets, improve natural gas processing efficiency and reduce operating costs, evaluating consolidation opportunities to maximize earnings, and renegotiating low-margin contracts. The principal goal of the contract renegotiation effort is to improve margins and reduce risk.
Oklahoma, Kansas, Wyoming, Montana and North Dakota 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.
See further discussion in the “Environmental and Safety Matters” section. Natural Gas Pipelines
Our FERC-regulated interstate natural gas pipeline assets transport natural gas through pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:
Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. We also have access to the major natural gas producing area in south central Kansas. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and
the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north.
We own underground natural gas storage facilities in Oklahoma, Kansas and Texas, which are connected to our intrastate natural gas pipeline assets.
Our transportation contracts for our regulated natural gas activities 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 at 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 also a fee business but are not subject to rate regulation by the OCC and have market-based rate authority from the FERC for certain types of services. Our Natural Gas Pipelines segment’s revenues are derived typically from fee-based services provided to our customers. Our fee-based services have increased primarily due to our previously completed capital projects including the Guardian Pipeline expansion and extension; Viking Gas Transmission Fargo lateral; and Midwestern Gas Transmission interconnect with the Rockies Express Pipeline. Our revenues are generated from the following types of fee-based contracts:
See Note K of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.
Demand - Demand for natural gas pipeline transportation service and natural gas storage is related directly to demand for natural gas in the markets that the natural gas pipelines and storage facilities serve, and is affected by weather, the economy and natural gas and NGL price volatility. Demand for our services can also be impacted as coal-fired electric generators consider natural gas as an alternative fuel. The effect of weather on our natural gas pipelines operations is discussed below under “Seasonality.” The strength of the economy directly impacts manufacturing and industrial companies that consume natural gas. Commodity price volatility can influence producers’ decisions related to the production of natural gas, the level of NGLs processed from natural gas, and natural gas storage injection and withdrawal activity. 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 differential between receipt and delivery points
along the pipeline, also known as basis differential, to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. 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 changes in the price of natural gas.
Seasonality - Demand for natural gas is seasonal. Weather conditions throughout North America can significantly impact regional natural gas supply and demand. High temperatures can increase demand for gas-fired electric generation needed to meet the electricity demand required to cool residential and commercial properties. Cold temperatures can lead to greater demand for our transportation services due to increased demand for natural gas to heat 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. 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 the value 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. The majority of our storage capacity is contracted under firm-service agreements. A small portion of our storage capacity is retained for operational purposes.
Competition - Our natural gas pipelines and storage facilities compete directly with other intrastate and interstate pipeline companies and other storage facilities in providing natural gas transportation and storage services. Our natural gas assets primarily serve local distribution companies, large industrial companies, municipalities, irrigation customers, power-generation facilities and marketing companies. Competition among pipelines and natural gas storage facilities is based primarily on fees for services, quality of services provided, current and forward natural gas prices, and proximity to natural gas supply areas and markets. Competition for natural gas transportation services continues to increase as new infrastructure projects are completed and the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. We believe that we compete effectively with our pipelines and storage assets due to their strategic locations connecting supply areas to market centers and other pipelines.
Likewise, our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas. In Kansas and Texas, natural gas storage may be regulated by the state and by the FERC for certain types of services. In Oklahoma, natural gas gathering and storage are not subject to rate regulation and have market-based rate authority for certain types of services.
See further discussion in the “Environmental and Safety Matters” section.
Natural Gas Liquids
refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from unprocessed natural gas, are connected to our gathering systems.
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, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, ethanol producers, refineries and propane distributors. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment.
Revenues for our Natural Gas Liquids segment are derived primarily from fee-based services provided to our customers and physical optimization of our assets. Our fee-based services have increased primarily due to our previously completed capital projects, including Overland Pass Pipeline and its associated lateral pipelines, and Arbuckle Pipeline. Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are defined as follows:
See Note K of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.
Our Natural Gas Liquids segment is 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 composite price of NGL products and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas, may influence processing plant NGL output. For the majority of 2010, ethane prices remained above natural gas prices on a relative Btu basis, which resulted in ethane recovery from natural gas processing plants that deliver NGLs to our natural gas liquids gathering pipelines. We expect ethane prices in 2011 to remain above natural gas prices on a relative Btu basis.
Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations impacts the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, fractionation and distribution services. Natural gas and propane are subject to weather-related seasonal demand. Other NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane/propane mix, propane, normal butane and natural gasoline are 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, Chicago, Illinois, and Gulf Coast regions, and the relative price differential between natural gas, NGLs and individual NGL products, which impact our NGL purchases, sales, distribution, exchange and storage revenue. When natural gas prices are higher relative to NGL prices, NGL production may decline, which could negatively impact our exchange services and transportation revenues. When the basis differential between the Mid-Continent and Gulf Coast market centers is narrow, optimization opportunities and NGL shipments may decline, resulting in a decline in margin. NGL storage revenue may be impacted by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.
Seasonality - Some NGL products produced, gathered and distributed by our natural gas liquids facilities are subject to weather-related seasonal demand, such as propane, which can be used to heat homes during the winter heating season and for agricultural purposes such as grain drying in the fall. Demand for butanes and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, may also be subject to some variability when automotive travel is higher and during seasonal periods when certain government restrictions on motor fuel blending products are in place. Competition - Our natural gas liquids business competes with other fractionators, intrastate and interstate pipeline companies, storage providers and gatherers for NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions. The factors that typically affect our ability to compete for NGL supplies are:
We are responding to these industry conditions by making capital investments to access new supplies, increase gathering and fractionation capacity, increase storage, withdrawal and injection capabilities and reduce operating costs so that we may compete effectively. We believe our fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.
See further discussion in the “Environmental and Safety Matters” section. FINANCIAL MARKETS LEGISLATION>
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted, representing a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies,
including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the proposals. We expect additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.
ENVIRONMENTAL AND SAFETY MATTERS
Federal, state and regional initiatives to regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. We estimate our direct greenhouse gas emissions annually as we collect certain greenhouse gas emission data for the previous year. Our most recent estimate indicates that our direct emissions were less than 3.5 million metric tons of carbon dioxide equivalents during 2009. This does not include the carbon dioxide-equivalents of product delivered to certain customers as required by the EPA’s Mandatory Greenhouse Gas Reporting Rule. The EPA’s Mandatory Greenhouse Gas Reporting Rule released in September 2009, requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011, and requires us to track the emission equivalents for all NGLs delivered to our customers. Also, the EPA has recently released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due March 31, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, the United States Congress has considered and may consider in the future legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rules or legislation have been enacted that assess any costs, fees or expense on any of these emissions.
In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, will have a minimal impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities. However, potential costs, fees or expenses associated with the potential adjustments are unknown.
In addition, the EPA issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.
Finally, while the Texas Commission on Environmental Quality (TCEQ) has been delegated primary responsibility for implementing federal environmental programs under the Clean Air Act and Clean Water Act in Texas, the EPA retains program oversight. Recently, an apparent division has arisen between TCEQ and EPA over key aspects of these Texas regulatory programs (including among others, air and new source review permitting). This division led to increased EPA scrutiny of TCEQ’s environmental permitting decisions and uncertainty with respect to how these programs will be administered in the future.
Pipeline Security -> Homeland Security’s Transportation Security Administration, along with the United States Department of Transportation, has completed a review and inspection of our “critical facilities” and identified no material security issues.
Environmental Footprint -> Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control; and (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere.
We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. In 2010, we received a Continuing Excellence Award for five years of active participation in the program including consistent reporting of emission-reduction activities by our Natural Gas Pipelines segment. We continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput. We expect to complete our annual estimate for 2010 during the second quarter of 2011 and will post the information on our website when available.
We do not directly employ any of the persons responsible for managing, operating or 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) under which 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 provides us an equivalent 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 operates Guardian Pipeline, Viking Gas Transmission and Midwestern Gas Transmission according to each pipeline’s operating agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. As of January 31, 2011, we utilized some or all of the services of 1,275 people in addition to the other resources provided by ONEOK and its affiliates.
INFORMATION AVAILABLE ON OUR WEBSITE>
We make available on our website (www.oneokpartners.com) copies of our Annual Reports, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct, Governance Guidelines, Partnership Agreement and the written charter of our
Audit Committee are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.
We also make available on our website the Interactive Data Files voluntarily submitted as Exhibit 101 to this Annual Report. In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.
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, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.
RISKS INHERENT IN OUR BUSINESS
Market volatility and capital availability could adversely affect our business.>
The capital and credit markets have experienced volatility and disruption. In many cases, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for companies. Our ability to grow could be constrained if we do not have regular access to the capital and credit markets. Similar or more severe levels of market disruption and volatility may have an adverse affect on us resulting from, but not limited to, disruption of our access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing cost and increasingly restrictive covenants.
Our operating results may be affected materially and adversely by unfavorable economic and market conditions.>
Economic conditions worldwide have from time to time contributed to slowdowns in the oil and gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices may have an impact on many of our customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations and liquidity.
A significant portion of our revenues are derived from the sale of commodities that are received as payment for natural gas gathering and processing services, for the transportation and storage of natural gas, and for the sale of purity NGL products in our natural gas liquids business. Commodity prices have been volatile and are likely to continue to be so in the future. The prices we receive for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not limited to the following:
These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services. As commodity prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, production could also decline.
We may not be able to generate sufficient cash from operations to allow us to pay quarterly distributions at current levels after the establishment of cash reserves and payment of fees and expenses, including payments to our affiliates.>
The amount of cash we can distribute to our unitholders depends principally upon the cash we generate from our operations, which includes activities with our affiliates. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to maintain future quarterly distributions at the current level. Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income.
We do not fully hedge against commodity price changes. 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 and crude oil prices. Market risk refers to the risk of loss arising from adverse changes in commodity prices. Our primary commodity price exposures arise from:
To manage the risk from market fluctuations in natural gas, NGL and crude oil prices, we use physical forward transactions and 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.
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 had 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 limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities.
Our inability to develop and execute growth projects and acquire new assets could result in reduced cash distributions to our 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 and cash flows and, accordingly, result in reduced cash distributions over time.
Growing our business by constructing new pipelines and plants 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 new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to our existing pipelines and existing gathering, processing, storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and fractionation facilities may require significant capital expenditures, which may exceed our estimates, and involves numerous regulatory, environmental, political, legal and weather-related uncertainties. Construction projects in our industry may increase demand for labor, materials and rights of way, 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 materially adversely affect our results of operations and financial condition.
Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.>
Any acquisition involves potential risks that may include, among other things:
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.
We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.>
We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.
Additionally, certain natural gas processing, natural gas liquids fractionators or other facilities (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our results of operations and cash flows.
Our operations are subject to operational hazards and unforeseen interruptions, which could materially adversely affect our business and for which we may not be adequately insured.>
Our operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering and transportation pipelines, storage facilities, and processing and fractionation plants. Operating risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes, and the performance of facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, the collision of equipment with our pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near our facilities) and catastrophic events such as explosions, fires, hurricanes, earthquakes, floods or other similar events beyond our control. It is also possible that our facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the operation of our pipeline caused by such an event could reduce revenues generated by us and increase expenses, thereby impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and we are not fully insured against all risks inherent to our business.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. If the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions declines substantially near our assets, our volumes and revenues could decline.>
Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions. Drilling and production are impacted by factors beyond our control, including:
In addition, drilling and production may be impacted by environmental regulations governing water discharge or regulation of drilling and production technologies including, but not limited to, hydraulic fracturing. If the level of drilling and production in any of these regions substantially declines, our volumes and revenue could be materially reduced.
We depend on natural gas supply from the Western Canada Sedimentary Basin for some of our interstate pipelines, primarily Viking Gas Transmission and our investment in Northern Border Pipeline that transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern United States market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and/or 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 and cash flows available for distributions.
Pipeline-integrity programs and repairs may impose significant costs and liabilities.>
Pursuant to a United States Department of Transportation rule, pipeline operators are required 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 rule also 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 results of these testing programs could cause us to incur significant capital and operating expenditures to make repairs or remediate, as well as initiate preventive or mitigating actions that are determined to be necessary.
The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not be pursued by the FERC, CFTC and/or the United States Congress in the future. In response to previous market power abuse by certain companies engaged in interstate commerce, the United States Congress, in the Energy Policy Act of 2005 (EPACT), developed requirements intended to ensure that the energy market is not impacted by the exercise of market power or manipulative conduct. The FERC then adopted the Market Manipulation Rules to implement the authority granted under EPACT. These rules are intended to prohibit fraud and manipulation and are subject to broad interpretation. EPACT also gave the FERC increased penalty authority for violations. In addition to the authority granted to the FERC under EPACT, the CFTC also has the authority to regulate market manipulation under the Commodities Exchange Act and the Dodd-Frank Act.
Our regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.>
Our regulated pipelines are subject to extensive regulation by the FERC and state regulatory agencies, which regulate most aspects of our pipeline business, including our transportation rates. Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to crude oil and natural gas liquids pipelines, interstate transportation rates must be just and reasonable and not unduly discriminatory.
Action by the FERC or a state regulatory agency could adversely affect our pipeline business’ ability to establish or charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates. 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.
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:
Various federal and state governmental authorities, including the 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 CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.
There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport, process and store, 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 increase significantly 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” and in Note M of the Notes to Consolidated Financial Statements in this Annual Report.
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 materially 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 materially adversely affect our products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect materially our profitability.
The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.>
In July 2010, the Dodd-Frank Act was enacted, which provides for new statutory and regulatory requirements for financial derivative transactions. Certain derivative transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions. However, the Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and to the parties to those transactions. Additionally, the Dodd-Frank Act calls for various regulatory agencies, including the SEC and the CFTC, to establish regulations for implementation of many of the provisions of the act. It also requires the CFTC to establish new position trading limits.
We expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations. These requirements could adversely affect market liquidity and pricing of derivative contracts, and the anticipated increased costs of compliance by dealers and counterparties will likely be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
In the competition for customers, we may have significant levels of uncontracted or discounted capacity on our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets.>
Our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage facilities for natural gas and NGL 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, processing, fractionation and in our storage assets, which could have a material adverse impact on our results of operations.
Terrorist attacks aimed at our facilities could adversely affect our business.>
Since the September 11, 2001, terrorist attacks, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments may subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
We are exposed to the credit risk of our customers or counterparties, 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 and counterparties. Our customers or counterparties may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral as we deem appropriate. If we fail to adequately
assess the creditworthiness of existing or future customers or counterparties, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact our results of operations. In addition, if any of our customers or counterparties file for bankruptcy protection, this could have a material negative impact on our results of operations.
Mergers among our customers and competitors could result in lower volumes being gathered, processed, fractionated, transported or stored on our assets, thereby reducing the amount of cash we generate.>
Mergers between our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing gathering, processing, fractionation and/or transportation systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers, and we could experience difficulty in replacing those lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes could result not only in less revenue but also in a decline in cash flow of a similar magnitude, which would reduce our ability to pay cash distributions to our unitholders.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect operations and cash flows available for distribution to our unitholders.>
Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, thus hiring outside resources, which decreases our productivity and increases our costs. This shortage of trained workers is the result of experienced workers reaching retirement age, combined with the difficulty of attracting new workers to the midstream energy industry. This shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations and cash flows available for distribution to our unitholders.
We may face significant costs to comply with the regulation of greenhouse gas emissions.>
Greenhouse gas emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. Various federal and state legislative proposals have been introduced to regulate the emission of greenhouse gases, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of greenhouse gases.
We believe it is likely that future governmental legislation and/or regulation may require us either to limit greenhouse gas emissions from our operations or to purchase allowances for such emissions that are actually attributable to our NGL customers. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations or when they will become effective. Several bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of greenhouse gases that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions. Emissions also could be taxed independently of limits.
In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of greenhouse gas emissions sooner and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that is adopted.
Future legislation and/or regulation designed to reduce greenhouse gas emissions could make some of our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with greenhouse gas regulatory requirements. Our future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to our customers.
We continue to monitor legislative and regulatory developments in this area. Although the regulation of greenhouse gas emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.
We may not be able to pass on the higher costs to our customers or recover all costs related to complying with climate change regulatory requirements, which could have a material adverse effect on our results of operations, cash flows or financial condition.
There is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.
RISKS INHERENT IN AN INVESTMENT IN US
ONEOK’s sale of substantial amounts of common units could reduce the market price of our common units.>
ONEOK and its affiliates own all of the Class B units, 5,900,000 common units and the entire 2-percent general partner interest in us, which together constituted a 42.8-percent ownership interest in us as of December 31, 2010. The Class B units are eligible to convert into common units on a one-for-one basis at ONEOK’s option. ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common units or other types of 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.
At a special meeting of the holders of our common units, held on May 10, 2007, the proposed amendments to our Partnership Agreement were not approved by the required two-thirds affirmative vote of our outstanding units, excluding the common units and Class B limited partner units held by ONEOK and its affiliates. As a result, effective April 7, 2007, ONEOK, as the sole holder of our Class B limited partner units, became entitled to receive increased quarterly distributions on its Class B units equal to 110 percent of the distributions paid with respect to our common units.
On June 21, 2007, ONEOK waived its right to receive the increased quarterly distributions on the Class B units for the period of April 7, 2007, through December 31, 2007, and continuing thereafter until ONEOK gives us no less than 90 days advance notice that it has withdrawn its waiver. ONEOK could withdraw such waiver and begin receiving such increased distributions, effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice. Since the proposed amendments to our Partnership Agreement were not approved by the requisite number of our common unitholders, if our common unitholders vote at any time to remove ONEOK or its affiliates as our general partner, quarterly distributions payable on the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.
Our unitholders have limited voting rights and are not entitled to elect our general partner’s directors, which could lower the trading price of our common units. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.>
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right to elect our general partner or its directors on an annual or other continuing basis. The Board of Directors of our general partner, including the independent directors, is chosen by the owners of the general partner and not by the unitholders.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, it may be difficult to remove ONEOK Partners GP or its officers or directors. ONEOK Partners GP may not be removed except upon the vote of the holders of at least 66-2/3 percent of our outstanding units voting together as a single class (excluding units held by ONEOK Partners GP and its affiliates). As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.
We rely on ONEOK, ONEOK Partners GP and NBP Services 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 Partners GP and NBP Services 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 Partners GP and NBP Services 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 Partners GP and NBP Services and third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.
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:
By purchasing a common unit, a common unitholder will be bound by the provisions in our Partnership Agreement, including the provisions discussed above.
ONEOK owns 100 percent of our general partner interest, and as a result of our February 2010 public offering of common units, ONEOK and its subsidiaries own a 42.8-percent aggregate equity interest in us. Our Partnership Agreement limits any fiduciary duties owed by our general partner and ONEOK to those duties that are specifically stated in our Partnership Agreement. Although ONEOK, through the Board of Directors of our general partner, has an obligation to manage us in a manner that is in, or not inconsistent with, our best interests, the Board of Directors of ONEOK has a fiduciary duty to manage our general partner in a manner beneficial to ONEOK. Six of the 10 members of the Board of Directors of our general partner are either members of ONEOK’s Board of Directors or executive management of ONEOK. Three independent members and one management member of the Board of Directors of our general partner are also members of ONEOK’s Board of Directors, with the management member being the only management member of ONEOK’s Board of Directors. Conflicts of interest may arise between ONEOK and its other affiliates and between us and our unitholders. In resolving these conflicts, our general partner may determine that the transaction is “fair and reasonable” to us, without the agreement of any other party, including the Audit Committee. In that regard, our general partner may favor its own interests and the interests of its other affiliates over the interests of our unitholders, as long as it does not take action that conflicts with our Partnership Agreement. These conflicts include, among others, the following situations:
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 general partner may transfer all, or any part of, its general partner interest to a third party without the consent of the unitholders. The members, shareholders or unitholders, as the case may be, of our new general partner may then be in a
position to replace all or a portion of the directors of our general partner with their own choices and to possibly control the decisions made by the Board of Directors of our general partner.
Our senior unsecured long-term debt has been assigned an investment-grade rating by Moody’s of “Baa2” (Stable) and by S&P of “BBB” (Stable). 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 or 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.
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.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.>
Unlike a corporation, our Partnership Agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt- service requirements, all of which are significant. The value of our units and other limited partner interests may decrease in correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity or incur debt to recapitalize.
An event of default may require us to offer to repurchase certain of our senior notes or may impair our ability to access capital.>
The indenture governing our senior notes due 2011 includes an event of default upon acceleration of other indebtedness of $25 million or more, and the indenture governing our other senior notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes 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.
Our indebtedness could impair our financial condition and our ability to fulfill our other obligations.>
As of December 31, 2010, we had total indebtedness of approximately $3.2 billion. Our indebtedness could have significant consequences. For example, it could:
We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph. 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.
Our debt agreements contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, or grant liens or make negative pledges. Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur. For example, our Partnership Credit Agreement contains a legal covenant requiring us to maintain a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.
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 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 other investments. 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, including FERC policies. 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 or other 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. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
Notwithstanding the foregoing, the issuance of equity securities ranking senior to the common units requires approval of a majority of the outstanding common units.
If at any time our general partner and its affiliates own 80 percent or more 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 unitholders’ voting rights by providing that any units held by a person or entity that owns 20 percent or more of our common 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.
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 our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes 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.
Despite the fact that we are a limited partnership under Delaware law, it is possible, in certain circumstances, for a partnership such as ours to be treated as a corporation for federal income tax purposes. 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 would likely pay additional state income taxes at varying rates. 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, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated free cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units. Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, starting January 1, 2008, we have been required to pay Texas franchise tax each year at a maximum effective rate of 0.7 percent of our gross revenue that is apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may reduce substantially the cash available for distribution to our common unitholders and, therefore, impact negatively the value of an investment in our common units. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to additional entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common or other units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.>
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the United States Congress considered substantive changes to the existing federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes or any other proposals will be enacted ultimately. Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders.
An IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.>
We have not requested a 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 and such positions may not ultimately be sustained. 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, any such contest with the IRS may impact materially and adversely the market for our common units and the price at which they trade. In addition, the costs of any such contest with the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
A unitholder’s share of our income will be taxable to the unitholder for federal income tax purposes even if the unitholder does not receive any cash distributions from us.>
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, a unitholder’s share of our taxable income will be taxable to the unitholder, which may require the payment of federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, even if the unitholder receives no 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 results from that income.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.
In addition, the federal income tax liability of a unitholder could be increased if we make a future offering of units and use the proceeds of the offering in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.
A unitholder will recognize a gain or loss for federal income tax purposes on the sale of common units equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the common units the unitholder sells will, in effect, become taxable income to a unitholder if the common units are sold at a price greater than the tax basis in those units, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized on a sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder who sells common units may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-United States 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 employee benefit plans and individual retirement accounts and non-United States persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, may be taxable to them as “unrelated business taxable income.” Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
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.
We may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.>
We prorate our items of income, gain, loss and deduction for federal income tax purpose between transferors and transferees of our common units each month based upon the ownership of our units as of the close of business on the last day of the preceding month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
Unitholders may 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 may be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if the unitholder does not live in any of those jurisdictions. Unitholders may 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. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax.
We determine our depreciation and cost-recovery allowances using federal income tax methods and may use methods that result in the largest deductions being taken in the early years after assets are placed in service. Some of the states in which we do business or own property may not conform to these federal depreciation methods. A successful challenge to these methods could adversely affect the amount of taxable income or loss being allocated to our unitholders for state tax purposes. It also could affect the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder's state tax returns. It is each unitholder's responsibility to file all United State federal, state and local tax return and foreign tax returns, as applicable. Our legal counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.
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.
The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.>
We will be considered to have technically terminated our partnership 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. For purposes of determining whether the 50-percent threshold has been met, multiple sales of the same interest will be counted only once.
Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being included in the unitholder’s taxable income for the year of termination. Our technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, and would be required to make new tax elections, and we could be subject to penalties if we are unable to determine that a technical termination occurred.
The IRS has recently announced a publicly traded partnership technical termination relief procedure, whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the technical termination.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.>
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
Natural Gas Gathering and Processing
Natural Gas Pipelines
Our storage includes 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. One of our natural gas storage facilities outside of Hutchinson, Kansas, has been idle since 2001. In compliance with a KDHE order, we began injecting brine into that facility in the first quarter of 2007 in order to ensure the long-term integrity of the idled facility. We expect to complete the injection process by the end of 2012. Monitoring of the facility and review of the data for the geo-engineering studies are ongoing, in compliance with a KDHE order, while we evaluate the alternatives for the facility. Following the testing of the gathered data, we expect that the facility will be returned to storage service, although most likely for a product other than natural gas. The return to service will require KDHE approval. It is possible, however, that testing could reveal that it is not safe to return the facility to service or that the KDHE will not grant the required permits to resume service.
Natural Gas Liquids
In addition, we lease approximately 2.9 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas. We also own and lease assets through an affiliate at the Bushton facility in Kansas, which includes 150 MBbl/d of fractionation capacity.
We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service during 2010 and 2009. The utilization rates of our FERC-regulated natural gas liquids gathering pipelines reflect Overland Pass Pipeline and its related lateral pipelines from the date they were placed in service until Overland Pass Pipeline Company was deconsolidated in September 2010. Our fractionation utilization rate reflects approximate proportional capacity associated with ownership interests noted above and for our Bushton facility.
Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a 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 (“Boles I”). >Plaintiffs brought suit on May 28, 1999, against ONEOK, Inc. and its Oklahoma Natural Gas division, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants. Plaintiffs sought class certification for their claims for monetary damages, alleging 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. On September 18, 2009, the Court denied the plaintiffs' motions for class certification, which, in effect, limits the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. The plaintiffs motion for reconsideration of the Court’s denial of class certification was denied on March 31, 2010.
Not applicable.
PART II>
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. The following table sets forth the high and low closing prices of our common units for the periods indicated:
At February 14, 2011, there were 711 holders of record of our 65,413,677 outstanding common units. ONEOK and its affiliates own all of the Class B units, 5,900,000 common units and the entire 2-percent general partner interest in us, which together constituted a 42.8-percent ownership interest in us.
The following table sets forth the quarterly cash distribution declared and paid on each of our common and Class B units during the periods indicated:
In January 2011, our general partner declared a cash distribution of $1.14 per unit ($4.56 per unit on an annualized basis) for the fourth quarter of 2010, which was paid on February 14, 2011, to unitholders of record as of January 31, 2011.
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 all cash receipts less adjustments for cash disbursements and net changes to reserves. Available cash will generally be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, our general partner receives:
Our Class B limited partner units are entitled to receive increased quarterly distributions equal to 110 percent of the distributions paid with respect to our common units. ONEOK, as the sole holder of our Class B limited partner units, has waived its right to receive the increased quarterly distributions on the Class B units. ONEOK retains the option to withdraw its waiver of increased distributions on our Class B units at any time by giving us no less than 90 days advance notice. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after the 90 days following delivery of the notice.
If our common unitholders vote at any time to remove ONEOK or its affiliates as our general partner, quarterly distributions payable on the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.
We paid cash distributions to our general and limited partners of $563.2 million, $500.3 million and $453.0 million for 2010, 2009 and 2008, respectively, which included an incentive distribution to our general partner of $103.5 million, $84.7 million and $69.9 million for 2010, 2009 and 2008, respectively. 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. The following performance graph compares the performance of our common units with the S&P 500 Index and the Alerian MLP Index during the period beginning on December 31, 2005, and ending on December 31, 2010. 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.
The following table sets forth our selected financial data for the periods indicated:
The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and the Notes to Consolidated Financial Statements in this Annual Report.
RECENT DEVELOPMENTS>
The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources,” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operation, our Consolidated Financial Statements and Notes to Consolidated Financial Statements for additional information.
Growth Projects> - We announced in 2010 and early 2011 approximately $1.8 billion to $2.1 billion in growth projects, primarily in the Williston Basin in North Dakota and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas, that will enable us to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities.
Williston Basin Projects - Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of 2010. The development of the reserves in these counties from the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics, with the associated natural gas production having a high NGL content. Current natural gas processing and natural gas liquids infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities.
We are the largest independent gatherer and processor of natural gas in the Williston Basin. With our Natural Gas Gathering and Processing segment’s existing infrastructure and acreage dedications, we are well positioned to provide midstream services to crude oil and natural gas producers as they develop Bakken Shale and Three Forks reserves. Additional natural gas liquids infrastructure is also needed due to the continued NGL production growth that has saturated the area’s current truck and railcar transportation capacity and market. The following provides additional details about our individual projects. Williston Basin Processing Plants and related projects - We announced plans to construct three new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota. In addition, we plan to make investments in related natural gas liquids infrastructure, expansions and upgrades to our existing gathering and compression infrastructure and new well connections associated with these plants. The Garden Creek plant and related projects are expected to be in service by the end of 2011 and cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant, which is expected to be in service during the third quarter of 2012, and related projects are expected to cost approximately $300 million to $355 million, excluding AFUDC. The Stateline II plant, which is expected to be in service during the first half of 2013, and related projects are expected to cost approximately $260 million to $305 million, excluding AFUDC. These projects are in our Natural Gas Gathering and Processing segment.
Bakken Pipeline and related projects - We announced plans to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, that will transport unfractionated NGLs from the Williston Basin in North Dakota to the Overland Pass Pipeline. The Bakken Pipeline will initially have capacity to transport up to 60 MBbl/d of unfractionated NGL production
from our natural gas gathering and processing assets in the Williston Basin originating in eastern Montana and connecting to the Overland Pass Pipeline in northeastern Colorado. The unfractionated NGLs will then be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Additional pump facilities could increase the Bakken Pipeline’s capacity to 110 MBbl/d. Supply commitments for the Bakken Pipeline will be anchored by NGL production from our natural gas processing plants. We are also discussing NGL supply commitments with third-party processors. Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be in service during the first half of 2013. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.
The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require additional pump stations and the expansion of existing pump stations on the Overland Pass Pipeline. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. Our anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC. The Bakken Pipeline and related projects are in our Natural Gas Liquids segment.
Bushton Fractionator Expansion - To accommodate the additional volume from the Bakken Pipeline, we will invest $110 million to $140 million, excluding AFUDC, to expand and upgrade our existing fractionation capacity at Bushton, Kansas, increasing our capacity to 210 MBbl/d from 150 MBbl/d. This project is expected to be in service during the first half of 2013 and is in our Natural Gas Liquids segment.
Cana-Woodford Shale and Granite Wash projects - In addition to the growth projects in the Williston Basin, we have also announced plans to invest approximately $270 million to $330 million, excluding AFUDC, in our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. The expansions and upgrades will increase our ability to accommodate the growing natural gas and NGL supply from producers and natural gas processors as drilling activities increase in these areas. These investments will expand our ability to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute purity NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. A portion of these investments will also allow us to increase utilization of our natural gas processing capacity in Oklahoma. We announced plans to construct more than 230 miles of natural gas liquids pipeline that will expand our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. The pipeline will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded. Additionally, we will install additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d. When completed, these projects are expected to add approximately 75 to 80 MBbl/d of raw, unfractionated NGLs to our existing natural gas liquids gathering systems. These projects are expected to be in service during the first half of 2012 and cost approximately $180 million to $240 million, excluding AFUDC. These projects are in our Natural Gas Liquids segment.
We will invest an additional $55 million in the Cana-Woodford Shale development in Oklahoma. The investments include approximately $20 million for new well connections in 2010 and 2011 to gather additional Cana-Woodford Shale natural gas volumes. In addition, we also completed in the fourth quarter of 2010 the connection of our Western Oklahoma natural gas gathering system to our existing Maysville natural gas processing facility in central Oklahoma and the connection of a new natural gas processing plant to our natural gas liquids gathering system. These projects are in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, respectively. Sterling I Pipeline Expansion - We will install seven additional pump stations for approximately $36 million, excluding AFUDC, along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by our Mid-Continent natural gas liquids infrastructure. The Sterling I pipeline transports purity NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center and is currently operating at capacity. The pump stations are expected to be in service in the second half of 2011. This project is in our Natural Gas Liquids segment.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 50.
Pass Pipeline Company and is expected to assume the role of operator in the second quarter of 2011. As a result of the transaction, we no longer control Overland Pass Pipeline Company and began accounting for our investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, we recognized a gain of approximately $16.3 million.
Commercial Paper Program >- In June 2010, we established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement. In July 2010, we repaid all borrowings outstanding under our Partnership Credit Agreement with the issuance of commercial paper.
Long-Term Debt >- In June 2010, we repaid $250 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, we no longer have any obligation to offer to repurchase the $225 million senior notes due March 2011, in the event that our long-term debt credit ratings fall below investment grade.
REGULATORY
In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, will have a minimal impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.
In addition, the EPA issued a proposed rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.
Financial Markets Legislation> - In July 2010, the Dodd-Frank Act was enacted, representing a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the proposals. We expect additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.
Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report. ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” is a disclosure-only standard, which did not have a material impact. See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements.
ESTIMATES AND CRITICAL ACCOUNTING POLICIES>
The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
The following is a summary of our most critical accounting policies, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring our 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 estimates and critical accounting policies with the Audit Committee of our Board of Directors.
For a derivative designated as a cash flow hedge, the effective portion of the gain or loss from a change in fair value of the derivative instrument is deferred in accumulated other comprehensive income (loss) until the forecasted transaction affects earnings, at which time the fair value of the derivative instrument is reclassified into earnings. The ineffective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is recognized in earnings.
We assess the effectiveness of hedging relationships quarterly by performing an effectiveness test on our hedging relationships to determine whether they are highly effective on a retrospective and prospective basis. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as cash flow hedges for which ineffectiveness is not material. However, if a derivative instrument is ineligible for cash flow hedge accounting or if we fail to appropriately designate it as a cash flow hedge, changes in fair value of the derivative instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings. For more information on commodity price sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
See Notes B and C of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of fair value measurements and derivatives and risk management activities.
Impairment of Goodwill and Long-Lived Assets, including Intangible Assets> - We assess our goodwill for impairment at least annually as of July 1. There were no impairment charges resulting from our 2010, 2009 or 2008 impairment tests.
As part of our impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for a reporting unit over a period of years.
Our estimates of fair values significantly exceeded the book values of our reporting units in our July 1, 2010, impairment test. Even if the estimated fair values used in our July 1, 2010, impairment tests were reduced by 10 percent, no impairment charges would have resulted. The following table sets forth our goodwill, by segment, at both December 31, 2010 and 2009:
We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no asset impairments in 2010, 2009 or 2008.
For the investments we account for under the equity method, the impairment test 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 re-evaluate the amount at which we carry our equity method investments to determine whether current events or circumstances warrant adjustments to our carrying value. We determined that there were no impairments to our investments in unconsolidated affiliates in 2010, 2009 or 2008.
Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.
See Notes A, D and E of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill and long-lived assets.
FINANCIAL RESULTS AND OPERATING INFORMATION
The following table sets forth certain selected consolidated financial results for the periods indicated:
2010 vs. 2009 - Energy markets were affected by higher commodity prices during 2010, compared with 2009. The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel. We completed more than $2.0 billion in growth projects at the end of 2008 and in 2009. Our 2010 operating results include the benefits from a full year of our completed projects, including the following projects placed in service in 2009:
Operating income increased 7 percent in 2010 compared with 2009. The increase in operating income for the 2010 period reflects the benefit of a full year of operations of our capital projects completed in 2009, resulting in higher NGL volumes in the Natural Gas Liquids segment; higher contracted natural gas transportation capacity on the Midwestern Gas Transmission and Viking Gas Transmission pipelines in the Natural Gas Pipelines segment; and an increase in Williston Basin volumes in our Natural Gas Gathering and Processing segment. Additionally, our Natural Gas Liquids and Natural Gas Pipelines segments produced higher storage margins, primarily as a result of contract renegotiations. Operating income also included the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. Operating income also benefited from lower than estimated ad valorem taxes associated with our capital projects completed in 2009 and lower outside service costs for maintenance at our fractionators in 2009, offset partially by incremental employee-related costs and property insurance costs associated with our capital projects completed in 2009.
These increases were offset partially by lower optimization margins in the Natural Gas Liquids segment due to limited NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf Coast NGL market centers until September 2010 and less favorable NGL price differentials; and decreased margins in our Natural Gas Gathering and Processing segment from lower natural gas volumes processed and sold in western Oklahoma and Kansas, selling our bankruptcy claims with Lehman Brothers in 2009 and lower natural gas volumes gathered in the Powder River Basin in Wyoming.
Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials. Additionally, in September 2010, we began accounting for our 50-percent investment in Overland Pass Pipeline Company, which includes the Overland Pass Pipeline and the D-J Basin and Piceance lateral pipelines, as an equity investment. Allowance for equity funds used during construction and capital expenditures decreased due primarily to the completion of our capital projects in 2009.
We expect continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin. The development of these reserves is being driven primarily by crude oil economics, with the associated natural gas production having a high NGL content. Current natural gas processing and natural gas liquids infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities. We have announced plans to invest $1.5 to $1.8 billion in the Williston Basin in North Dakota and Bushton, Kansas to serve the needs of crude oil and natural gas producers.
In addition to the growth projects in the Williston Basin, we have also announced plans to invest $270 to $330 million to expand and upgrade our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas, to accommodate the growing natural gas and NGL supply from producers and natural gas processors as drilling activities increase in these areas. These investments will expand our ability to transport unfractionated NGLs from these supply areas to fractionation facilities in Kansas, Oklahoma and Texas and distribute purity NGL products to Mid-Continent, Gulf Coast and upper Midwest market centers and allow us to increase utilization of our natural gas processing capacity in Oklahoma.
Additional NGL fractionation capacity, which benefits optimization activities in our Natural Gas Liquids segment, became available on September 1, 2010. Additional capacity also will become available when our fractionation services agreement with Targa Resources Partners begins in the second quarter 2011. As part of our growth projects announced in 2010 and early 2011, the expansion of the Sterling I natural gas liquids distribution pipeline, expected to be completed in the second half of 2011, and our expansion of the Arbuckle Pipeline, expected to be completed in the first half of 2012, will enable the transportation of additional NGLs to the Gulf Coast market.
We expect these projects will increase our fee-based earnings, as well as improve our margins from POP contracts in our Natural Gas Gathering and Processing segment and our exchange and optimization activities in our Natural Gas Liquids segment. 2009 vs. 2008 - Energy markets were affected by decreased commodity prices during 2009 compared with 2008. The decrease in commodity prices had a direct impact on our revenues and cost of sales and fuel.
Operating income in 2009 decreased 15 percent when compared with 2008, due primarily to lower realized commodity prices in the Natural Gas Gathering and Processing segment and less favorable NGL price differentials and a prior-year operational measurement gain in the Natural Gas Liquids segment. These decreases were offset partially by substantially higher NGL volumes in the Natural Gas Liquids segment, associated primarily with the completion of the Overland Pass Pipeline and related expansion projects and the Arbuckle Pipeline, as well as new NGL supply connections; higher natural gas transportation margins as a result of the completion of the Guardian Pipeline expansion and extension and an increase in contracted volumes on Midwestern Gas Transmission as the result of a new interconnection with the Rockies Express Pipeline in the Natural Gas Pipelines segment; and higher natural gas volumes processed and sold in the Natural Gas Gathering and Processing segment. Additionally, operating costs and depreciation and amortization expense increased for 2009 as compared to 2008 due to higher employee-related costs and incremental costs associated with the capital projects completed at the end of 2008 and in 2009.
Equity earnings from investments decreased due primarily to lower subscription volumes and rates on Northern Border Pipeline due to narrower natural gas price differentials between the markets it serves. Additionally, we benefited from an $8.3 million gain due to Northern Border Pipeline’s sale of Bison Pipeline LLC in 2008.
Interest expense increased due primarily to our March 2009 debt issuance and a decrease in capitalized interest due to the completion of our capital projects.
Allowance for equity funds used during construction and capital expenditures decreased due primarily to the completion of our capital projects in 2009.
More information regarding our results of operations is provided in the following discussion of operating results for each of our segments. Natural Gas Gathering and Processing
Selected Financial Results >- The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:
2010 vs. 2009 - Net margin decreased primarily as a result of the following:
Capital expenditures increased due primarily to our recently announced capital projects in the Williston Basin. We expect capital expenditures to increase in 2011 as construction continues on these projects. See more detail of our growth projects and projected capital expenditures at “Recent Developments” and “Liquidity and Capital Resources.”
2009 vs. 2008 - Net margin decreased primarily as a result of the following:
Operating costs decreased due primarily to $2.6 million in lower chemicals costs and $2.0 million in lower maintenance costs, offset partially by higher employee-related costs.
Depreciation and amortization increased primarily as a result of our Grasslands natural gas processing plant expansion completed in 2009. Equity earnings from investments decreased primarily as a result of lower natural gas volumes gathered in our equity investments, which are located primarily in the Powder River Basin of Wyoming.
Capital expenditures decreased due primarily to the completion of a pipeline expansion project into the Cana-Woodford Shale in September of 2008 in Oklahoma and the Grasslands natural gas processing plant expansion completed in March 2009.
Selected Operating Information> - The following tables set forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
Natural Gas Pipelines
Selected Financial Results and Operating Information >- The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
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