Table of Contents

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, 2007.

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

ONEOK PARTNERS, L.P.

(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 if disclosure of delinquent filers pursuant to Item 405 of Registration S-K 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 checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer X                                     Accelerated filer                                               Non-accelerated filer __

Indicate by checkmark 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, 2007, was $3.2 billion.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Table of Contents

ONEOK PARTNERS, L.P.

2007 ANNUAL REPORT ON FORM 10-K

In this Annual Report on Form 10-K, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P. and its subsidiary, ONEOK Partners Intermediate Limited Partnership and its subsidiaries, formerly known as Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership, respectively.

2

Table of Contents

GLOSSARY

The abbreviations, acronyms, industry terminology and certain other terms used in this Annual Report on Form 10-K are defined as follows:

3

Table of Contents

The statements in this Annual Report on Form 10-K 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” 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 our goals 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—Forward-Looking Statements in this Annual Report on Form 10-K for the year ended December 31, 2007.

4

Table of Contents

PART I

ITEM 1. BUSINESS

GENERAL

ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.” We own and manage natural gas gathering, processing, storage and interstate and intrastate pipeline assets and natural gas liquids gathering and distribution pipelines, storage and fractionators, connecting much of the natural gas and NGL supply in the Mid-Continent and Gulf Coast regions with key market centers in Conway, Kansas, Mont Belvieu, Texas, and Chicago, Illinois. We also own a 50 percent equity interest in a leading transporter of natural gas imported from Canada into the United States.

DESCRIPTION OF BUSINESS SEGMENTS

In July 2007, we announced a series of organizational changes that led to the realignment of our previous business segments. Our financial results are now reported in these four segments: (i) Natural Gas Gathering and Processing, which remains unchanged, (ii) Natural Gas Pipelines, which is comprised of our former interstate natural gas pipelines segment and the natural gas assets of our former pipelines and storage segment, (iii) Natural Gas Liquids Gathering and Fractionation, which remains unchanged, and (iv) Natural Gas Liquids Pipelines, which is comprised of the natural gas liquids assets of our former pipelines and storage segment. Prior periods have been restated to reflect these segment changes. The change reflects the increasing scale of the natural gas liquids business, which has grown significantly since 2006. Our natural gas liquids business is expanding as we integrate the assets acquired in October 2007 from a subsidiary of Kinder Morgan Energy Partners, L.P. (Kinder Morgan) into our Natural Gas Liquids Pipelines segment and complete our other internal growth projects.

Our operations are divided into these strategic business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, as follows:

For financial and statistical information regarding our business segments, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. See Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of sales to unaffiliated customers, operating income and total assets by business segment.

Partnership Structure

We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP, which consists of six members. Three of our Board members qualify as independent under the listing standards of the NYSE and also serve as the Audit Committee of ONEOK Partners GP. ONEOK Partners GP is a wholly owned subsidiary of ONEOK. ONEOK owns a 45.7 percent aggregate equity interest in us.

Business Strategy

Our primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distributions over time. Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. We focus on safe, environmentally sound and compliant operations for our employees, contractors, customers and the public.

Our strategy is to expand and acquire assets in the United States related to gathering, processing, fractionating, storing and marketing natural gas and NGLs that will utilize our core competencies, minimize commodity price risk and provide long-

5

Table of Contents

term, sustainable and stable cash flows. We finance our acquisitions and capital expenditures with a mix of operating cash flows, debt and equity.

In April 2006, we acquired certain companies comprising ONEOK’s former gathering and processing, natural gas liquids, and pipeline and storage segments, collectively referred to as the “ONEOK Energy Assets” from ONEOK, the parent company of our general partner, in a series of transactions, collectively referred to as the “ONEOK Transactions,” which are described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Significant Acquisitions and Divestitures.” These assets complemented our core competencies related to energy services and diversified our portfolio of assets. The assets we acquired from ONEOK enabled us to enter into energy-related businesses in the well-established Mid-Continent region and key natural gas liquids markets in Kansas and Texas. In addition, our expanded asset portfolio positions us for future organic growth projects, which we believe currently offer the most attractive growth opportunities for us.

SIGNIFICANT DEVELOPMENTS IN 2007 AND EARLY 2008

In February 2008, we announced plans to construct a 78-mile natural gas liquids gathering pipeline to connect two natural gas processing plants in the Woodford Shale area in southeast Oklahoma at a cost of approximately $25 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. These two plants are expected to produce approximately 25 MBbl/d of unfractionated NGLs. Until the Arbuckle Pipeline project is completed, the natural gas liquids production will be transported by our existing Mid-Continent natural gas liquids pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported to our Mont Belvieu, Texas, fractionation facility.

In October 2007, we completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland.

In September 2007, we completed an underwritten public debt offering of $600 million to finance the assets acquired from Kinder Morgan and to repay outstanding debt under the 2007 Partnership Credit Agreement, which was incurred to fund our internal growth capital projects.

During 2007, we began construction on the Overland Pass Pipeline Company joint-venture project with a subsidiary of The Williams Companies, Inc. (Williams). Overland Pass Pipeline Company is building a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs, which can be increased to approximately 150 MBbl/d with additional pump facilities. This project has received the required approvals of various state and federal regulatory authorities, and we are constructing the pipeline with start-up currently scheduled for the second quarter of 2008.

In March 2007, we announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be transported by the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required state and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the second quarter of 2009.

In March 2007, we announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquids and will connect our existing Mid-Continent infrastructure with our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. Construction of the pipeline will require permits from various federal, state and local regulatory bodies. Construction is currently expected to begin in mid-2008 and will be completed by early 2009.

In March 2007, we announced the expansion of our Grasslands natural gas processing facility in North Dakota. The Grasslands facility is our largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to

6

Table of Contents

approximately 12 MBbl/d from 8 MBbl/d. The expansion project is expected to come on-line in phases, with the final phase currently expected to be on-line in the third quarter of 2008.

In January 2007, Fort Union Gas Gathering announced that it will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines and approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. The expansion will occur in two phases. Phase 1 was placed in service during the fourth quarter of 2007. Phase 2 is currently expected to be in service during the second quarter of 2008. We own approximately 37 percent of Fort Union Gas Gathering.

NARRATIVE DESCRIPTION OF BUSINESS

Natural Gas Gathering and Processing

Business Strategy - We focus on safe, environmentally sound and compliant operations for our employees, contractors, customers and the public. We pursue growth through additional well connections, system expansions and strategic acquisitions. We seek to restructure expiring contracts to mitigate commodity exposure. We also seek to provide reliable, efficient and consistent operations through optimization of our natural gas gathering and processing operations while managing costs.

Segment Description - Our former gathering and processing segment is now called our Natural Gas Gathering and Processing segment. As part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Significant Acquisitions and Divestitures,” we acquired all of ONEOK’s natural gas gathering and processing assets and combined them with our legacy gathering and processing segment assets in April 2006.

Our operations include gathering of natural gas production from oil and natural gas wells. We gather raw natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather raw natural gas in three producing basins in the Rocky Mountain region: (i) the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, (ii) the Powder River Basin of Wyoming and (iii) the Wind River Basin of Wyoming.

Through gathering systems, raw natural gas volumes are aggregated for removal of water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is generally shipped to fractionators, where by applying heat and pressure, the unfractionated NGL stream is separated into marketable purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products can then be stored, transported and marketed to a diverse customer base.

Our Natural Gas Gathering and Processing segment gathers and processes raw natural gas. We generally gather and process gas under the following types of contracts.

7

Table of Contents

Excluding any gain on sale of assets, operating income from our Natural Gas Gathering and Processing segment was 42 percent, 46 percent and 17 percent of our consolidated operating income in 2007, 2006 and 2005, respectively. Operating revenue of this segment is derived primarily from POP and fee contracts. We use derivative instruments to mitigate our sensitivity to fluctuations in the price of natural gas, condensate and NGLs. Our Natural Gas Gathering and Processing segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for 35 percent of our Natural Gas Gathering and Processing segment’s revenues in 2007 and 2006. Our Natural Gas Gathering and Processing segment had no intersegment sales in 2005. A portion of our revenues are from ONEOK and its affiliates.

Market Conditions and Seasonality - Supply - Natural gas supply is affected by rig availability, operating capability and producer drilling activity, which is sensitive to commodity prices, geological success, available capital and regulatory control. Relatively high natural gas and crude oil prices, as well as favorable long-term projections of U.S. demand, continued to drive increased drilling in 2007 in the Mid-Continent and Rocky Mountain regions, which are our primary supply regions.

In the Mid-Continent region, the gathering and processing assets we acquired in the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas are well established. However, we anticipate continuing volumetric declines in certain fields that supply our gathering and processing operations. Additionally, there is excess processing capacity, particularly in the Hugoton production region, which includes the Bushton Plant. Partly as a result of the Bushton Plant’s inability to recover certain NGLs, such as ethane, the plant was at an economic disadvantage to the region’s other cryogenic plants, and it was temporarily idled on January 1, 2007. See discussion on page 26.

In the Williston Basin, we connected more wells in 2007 than in prior years as a result of increased drilling activity. Transportation and refining capacity constraints for crude oil continue to only moderately impact natural gas production in the Williston Basin. Further development of the Big George coals, located in the center of the Powder River Basin, resulted in greater volumes during 2007, compared with 2006, for our wholly owned assets and joint-venture interests in Bighorn Gas Gathering and Fort Union Gas Gathering.

Demand - Demand for gathering and processing services is typically aligned with the supply of natural gas, which generally flows from a producing area at a relatively steady but gradually declining pace over time unless new reserves are added. Our plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing, within limits, the temperature and pressure at which raw natural gas is processed, we can produce more of the specific commodity that has the most favorable price or price spread.

Commodity Prices - Crude oil, natural gas and NGL prices are volatile due to market conditions. Storage injection and withdrawal rates, as well as available storage capacity, can also have an impact on commodity prices. We are exposed to market risk associated with adverse changes in commodity prices. Our primary exposures arise from the sale of natural gas, NGLs and condensate with respect to our processing contracts. To a lesser extent, we are exposed to the relative price differential between NGLs and natural gas, the risk of price fluctuations and the cost of intervening transportation at various market locations, and the demand for our products by the petrochemical industry and others.

Seasonality - Some of this segment’s products are subject to weather-related seasonal demand. Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses. Warm temperatures typically drive demand for natural gas used for gas-fired electric generation used to cool residential and commercial properties. Demand for iso-butane and natural gasoline, which are primarily used by the refining industry as blending stocks for motor

8

Table of Contents

fuel, may also be subject to some variability when automotive travel is higher. During periods of peak demand for a certain commodity, prices for that product typically increase, which influences processing decisions.

Competition - The gathering and processing business remains relatively fragmented despite significant consolidation in the industry. We compete for natural gas supplies with major integrated exploration and production companies, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions.

Due to the unprecedented strength of the energy commodity market over the past two years, gathering and processing rates have become increasingly competitive. As a result, we may not be successful in obtaining new natural gas supplies to offset declines and may lose some existing supplies to competitors. We are responding to these industry conditions by making capital investments to improve plant processing flexibility and reduce operating costs, evaluating consolidation opportunities to maximize earnings, selling assets in non-core operating areas and renegotiating unprofitable contracts. Contracts covering approximately 84 percent of our volumes under keep-whole contracts contain language that effectively converts these contracts into fee contracts when the keep-whole spread is negative.

Government Regulation - The FERC has traditionally maintained that a processing plant is not a facility for the transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in removing NGLs and, therefore, we believe, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We believe our gathering facilities and operations meet the criteria used by the FERC for non-jurisdictional gathering facility status. We can transport residue gas from our plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.

Oklahoma and Kansas also have statutes regulating, to various degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

Natural Gas Pipelines

Business Strategy - We focus on safe, environmentally sound and compliant operations for our employees, contractors, customers and the public. We seek to maintain a competitive cost structure and increase throughput and growth of our existing natural gas pipelines and storage assets through extensions and expansions supported by long-term transportation and reservation contracts.

Segment Description - Our Natural Gas Pipelines segment is comprised of our previous interstate natural gas pipelines segment and the natural gas assets of our previous pipelines and storage segment. This segment primarily operates regulated natural gas transmission pipelines, natural gas storage facilities, and non-processable natural gas gathering facilities. We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act.

Our interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas pipelines in Montana, North Dakota, South Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission, OkTex Pipeline and a 50 percent interest in Northern Border Pipeline.

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 east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market.

We own or reserve storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.

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

9

Table of Contents

agency proceedings known as rate cases. In Texas and Kansas, natural gas storage service is a fee business that may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas gathering and natural gas storage operations are not subject to rate regulation and have market-based rate authority from the FERC for certain types of services.

Our Natural Gas Pipelines segment’s revenues are typically derived from fee services from the following types of contracts.

Excluding any gain on sale of assets, operating income from our Natural Gas Pipelines segment was 25 percent, 31 percent and 83 percent of our consolidated operating income in 2007, 2006 and 2005, respectively. Our Natural Gas Pipelines segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for less than 1 percent of our Natural Gas Pipelines segment’s revenues in 2007 and 2006, respectively. Our Natural Gas Pipelines segment had no intersegment sales in 2005. A portion of our revenue is derived from services provided to ONEOK and its affiliates.

Market Conditions and Seasonality - Supply - The supply of natural gas for Viking Gas Transmission and Northern Border Pipeline originates in Canada. Significant factors that can impact the supply of Canadian natural gas transported by our pipelines are the Canadian natural gas available for export, Canadian storage capacity and demand for Canadian natural gas in other U.S. consumer markets. The supply of natural gas to our Guardian, Midwestern and Mid-Continent pipelines and storage assets currently depends on the pace of natural gas drilling activity by producers and the decline rate of existing production in the major natural gas production areas in the Mid-Continent region, including the Anadarko Basin, Hugoton Basin, Central Kansas Uplift Basin and Permian Basin. United States natural gas drilling rig counts increased in 2007 compared with 2006. The natural gas supply from the Gulf Coast also supports our Mid-Continent and upper Midwest pipeline facilities. This supply source is primarily dependent on offshore Gulf Coast production and, to a lesser degree, imports of liquefied natural gas.

Demand - Demand for pipeline transportation service and natural gas storage is directly related 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. 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 rely on natural gas. Commodity price volatility can influence customers’ decisions related to the production of natural gas versus NGLs 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 spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. Natural gas storage revenue is impacted by the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market. Our fuel costs and the value of the retained fuel in-kind are also impacted by adverse changes in the commodity price of natural gas.

Seasonality - Demand for natural gas is seasonal. Weather conditions throughout the United States can significantly impact regional natural gas supply and demand. High temperatures can increase demand for gas-fired electric generation to cool residential and commercial properties. Low precipitation levels can impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region. Cold temperatures can lead to greater demand for our transportation services due to increased demand for natural gas.

To the extent that pipeline capacity is contracted under firm service transportation agreements, revenue, which is generated primarily from demand charges, is not significantly impacted by seasonal throughput variations. However, when transportation agreements expire, seasonal demand can impact re-contracting of firm service transportation capacity.

10

Table of Contents

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 term agreements. A small portion of our storage capacity is retained for operational purposes and seasonal market activity.

Competition - Our Natural Gas Pipelines segment competes with other pipeline companies and other storage facilities for natural gas. Competition among pipelines and natural gas storage facilities is based primarily on fees for service and proximity to natural gas supply areas and markets. Competition for natural gas transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets.

Government Regulation - Our interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of this business segment, such as transportation of natural gas, rates and charges for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities, and initiation and discontinuation of services.

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.

Natural Gas Liquids Gathering and Fractionation

Business Strategy - We focus on safe, environmentally sound and compliant operations for our employees, contractors, customers and the public. We seek to maximize our value by increasing facility utilization and efficiently managing the operating costs of our natural gas liquids assets, which consist of facilities that gather, fractionate and treat NGLs and store NGL purity products in the Mid-Continent and Gulf Coast regions.

Segment Description - Our former natural gas liquids segment is now called our Natural Gas Liquids Gathering and Fractionation segment. As part of the ONEOK Transactions described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Significant Acquisitions and Divestitures,” in April 2006, we acquired all of ONEOK’s natural gas liquids assets and created a new segment that consisted solely of these newly acquired natural gas liquids assets.

Our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs produced by natural gas processing plants located in Oklahoma, Kansas, the Texas panhandle and the Texas Gulf Coast, and stores and markets NGL products. We connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key natural gas liquids market centers in Conway, Kansas, and Mont Belvieu, Texas.

Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications, which limit NGLs in the natural gas stream by 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 our fractionators. A fractionator, by applying heat and pressure, separates the unfractionated NGL stream into marketable purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products are then stored and/or distributed to our customers, such as petrochemical plants, heating fuel users and motor gasoline manufacturers.

Operating revenue of this segment is derived primarily from exchange services, optimization, isomerization and storage.

11

Table of Contents

Excluding any gain on sale of assets, operating income from our Natural Gas Liquids Gathering and Fractionation segment was 25 percent and 22 percent of our consolidated operating income in 2007 and 2006, respectively. We did not have a Natural Gas Liquids Gathering and Fractionation segment prior to 2006. Our Natural Gas Liquids Gathering and Fractionation segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for less than one percent of our Natural Gas Liquids Gathering and Fractionation segment’s revenues in 2007 and 2006, respectively.

Market Conditions and Seasonality - Supply - Supply for our Natural Gas Liquids Gathering and Fractionation segment depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production, and the liquids content of the natural gas that is produced and processed. Our Mont Belvieu fractionation operation receives NGLs from a variety of processors and pipelines located in the Gulf Coast, west and central Texas, and the Rocky Mountain regions.

Our NGL gathering pipelines are also affected by operational or market-driven changes that impact the output of natural gas processing plants to which they are connected. The differential between the 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 output. Typically, the forward price of ethane compared with the forward price of natural gas provides minimal or no processing spread. However, when the physical transactions occur, the price of ethane to natural gas has historically provided a positive processing spread. During 2007, ethane values remained above those of natural gas on a relative price basis, which resulted in ethane recovery from processing plants that deliver to our natural gas liquids gathering pipelines.

Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations impacts the volume of unfractionated NGLs produced by processing plants, thereby affecting the demand for natural gas liquids gathering and fractionation services. Natural gas and propane are subject to weather-related seasonal demand. Other products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as iso-butane and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, ethane, and an ethane/propane mix. This ethane/propane mix is used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.

Commodity Prices - In recent years, crude oil, natural gas and NGL prices have been volatile due to market conditions. We are exposed to market risk associated with adverse changes in the price of NGLs, the basis differential between the Mid-Continent and Gulf Coast regions, and the relative price differential between natural gas, NGLs and individual NGL products, which impact our NGL purchases, sales, 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 revenue. When the basis differential between the Mid-Continent and Gulf Coast regions is narrow, optimization opportunity and margins may decline. NGL storage revenue may be impacted by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.

Seasonality - Some NGL products produced by our natural gas liquids facilities are subject to weather-related seasonal demand, such as propane, which is primarily used to heat residential properties during the winter heating season. Demand for iso-butane and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, may also be subject to some variability when automotive travel is higher.

Competition - We compete with other fractionators, storage providers and gatherers for natural gas liquids supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions. We are making capital investments to access new supplies, increase gathering and fractionation capacity, increase storage capabilities and reduce operating costs so that we may compete more effectively.

Government Regulations - Revenues generated by our pipelines in both Oklahoma and Kansas are not regulated by the FERC or those states’ respective corporation commissions.

Natural Gas Liquids Pipelines

Business Strategy - We focus on safe, environmentally sound and compliant operations for our employees, contractors, customers and the public. We seek to increase throughput and continue to provide cost-effective transportation for NGLs between the Mid-Continent, the Gulf Coast and the Midwest markets near Chicago, Illinois. We pursue growth of our interstate natural gas liquids pipelines by making capital investments to expand our access to new supplies and increase our pipeline capacity.

12

Table of Contents

Segment Description - Our Natural Gas Liquids Pipelines segment is comprised of the natural gas liquids assets of our previous pipelines and storage segment, and our natural gas liquids and refined petroleum products pipeline systems and related assets acquired from Kinder Morgan in October 2007. This segment operates FERC-regulated natural gas liquids gathering and distribution pipelines and associated above- and below-ground storage facilities. Our natural gas liquids gathering pipelines deliver unfractionated NGLs gathered in Oklahoma, Kansas and the Texas panhandle to our Mid-Continent fractionation facilities in Medford, Oklahoma. Our natural gas liquids distribution pipelines deliver NGL products to the natural gas liquids market hubs in Conway, Kansas, and Mont Belvieu, Texas. Through our acquisition of the natural gas liquids assets from Kinder Morgan, we acquired terminal and storage facilities as well as natural gas liquids and refined petroleum products pipelines that connect our Mid-Continent assets with the Midwest markets near Chicago, Illinois. Our natural gas liquids gathering and distribution pipelines operate in Oklahoma, Kansas, Nebraska, Missouri, Iowa, Illinois and Texas. We have terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.

Operating revenue for this segment is primarily derived from transporting product under our FERC-regulated tariffs. Tariffs specify the rates we can charge our customers and the general terms and conditions for NGL transportation service on our pipelines. Our tariffs include specifications regarding the receipt and delivery of NGLs at points along the pipeline systems. We generally charge tariff rates under a FERC-approved indexing methodology, which allows charging rates up to a prescribed ceiling that changes annually based on the year-to-year change in the Producer Price Index for finished goods. The FERC also permits interstate natural gas liquids pipelines to support rates by using a cost-of-service methodology, competitive market price or an agreement with a pipeline’s non-affiliated shipper.

Our storage services are offered through a combination of market-based rates and FERC-regulated tariffs and are generally used for operational purposes and to store our customers’ NGL products. Under some of our FERC-regulated tariffs, customers are allotted earned storage capacity based upon their utilization of transport services. When a customer exceeds its earned storage capacity, we charge the customer an excess storage fee. In some of our product storage agreements, we may charge customers storage reservation fees to reserve a specific storage capacity or we may charge customers based on the quantity of capacity utilized.

Excluding any gain on sale of assets, operating income from our Natural Gas Liquids Pipelines segment was 9 percent and 7 percent of our consolidated operating income in 2007 and 2006, respectively. We did not have a Natural Gas Liquids Pipelines segment prior to 2006. Our Natural Gas Liquids Pipelines segment had no single external customer from which it received 10 percent or more of consolidated revenues. Intersegment sales accounted for 83 percent and 100 percent of our Natural Gas Liquids Pipelines segment’s revenues in 2007 and 2006, respectively.

Market Conditions and Seasonality - Supply - The supply for our Natural Gas Liquids Pipelines segment depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production, and the liquids content of the natural gas that is produced and processed. Our unfractionated NGLs are primarily gathered from natural gas processing plants in Oklahoma, Kansas and the Texas panhandle. The supply of NGLs gathered are affected by operational or market-driven changes that impact the output of natural gas processing plants to which we 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 output. Typically, the forward price of ethane compared with the forward price of natural gas provides minimal or no processing spread. However, as the prices settle, the price of ethane to natural gas has historically provided a positive processing spread. During 2007, ethane prices remained above natural gas prices on a relative 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 processing plants, which affects the demand for our NGL gathering and distribution services. Propane is subject to weather-related seasonal demand. Other products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline, which are used by the refining industry as blending stocks for motor fuel. Ethane/propane mix is used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.

Commodity Prices - In recent years, crude oil, natural gas and NGL prices have been volatile due to market conditions. We are exposed to market risk associated with adverse changes in the price of NGLs, the basis differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions, and the relative price differential between natural gas, unfractionated NGLs and individual NGL products, which impact the distribution of NGL products. When natural gas prices are higher relative to NGL prices, NGL production may decline, which could negatively impact the revenues of our gathering and distribution activities. When the basis differential between the Mid-Continent, Chicago, Illinois, and the Gulf Coast regions are narrow, NGL shipments may decline, resulting in a reduction of transportation revenues.

13

Table of Contents

Seasonality - Some NGLs gathered and distributed by our natural gas liquids pipeline facilities are subject to weather-related seasonal demand, such as propane, which is primarily used to heat residential properties during the winter heating season and for agricultural purposes such as grain drying in the fall. Demand for normal butane, 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 when automotive travel is higher.

Competition - Our Natural Gas Liquids Pipelines segment competes with other pipeline companies and other storage facilities for NGLs. Competition among pipeline companies and NGL storage facilities is based primarily on fees for service and proximity to natural gas liquids supply areas and markets.

Government Regulation - Our interstate natural gas liquids pipelines are regulated by the FERC, which regulates virtually all aspects of this business segment, such as transportation of NGLs and refined products, rates and charges for services, depreciation and amortization policies, and initiation and discontinuation of services. The KCC regulates intrastate transportation of NGLs and refined products in Kansas.

Other

Segment Description - Our Other segment includes Black Mesa, which is a pipeline designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona, and terminates at the Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint-use area until December 31, 2005.

On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired, and our coal slurry pipeline operations were shut down. In June 2006, Southern California Edison Company (SCE) completed a comprehensive study of the water source, coal supply and transportation issues, and announced that it would no longer pursue the resumption of plant operations. In February 2007, another Mohave co-owner, Salt River Project, announced it was ending its efforts to return the plant to service. We plan to either divest the Black Mesa pipeline or commence decommissioning of the pipeline during 2008.

ENVIRONMENTAL AND SAFETY MATTERS

Information about our environmental matters is included in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Pipeline Safety - We are subject to United States Department of Transportation integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on segments of a pipeline that pass through densely populated areas or near specifically identified sites that are designated as high consequence areas. To our knowledge, we are substantially in compliance with all material requirements associated with the various regulations.

Air and Water Emissions - The federal Clean Air Act and Clean Water Act and analogous state laws impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federal operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants discharged in United States water.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. After receiving these reports, Homeland Security will identify which sites are required to implement security measures. Homeland Security is in the initial stages of implementing this rule, and the extent to which the rule will require us to undertake additional expenditures for site security is uncertain at this point.

14

Table of Contents

Climate Change - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) maintaining an accurate greenhouse gas emissions inventory, (ii) improving the efficiency of our various pipeline and gas processing facilities, (iii) following developing technologies for emission control, (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere, and (v) analyzing options for future energy investment.

Currently, operating entities within our Partnership participate in the gathering and processing sector and the transmission sector of the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. In addition, we continue to focus on reducing methane loss through expanded implementation of best practices across our operations and analyzing options for additional emission reductions, including (i) closing older facilities and routing products to more efficient facilities, (ii) self-imposing permit limits at facilities where operationally feasible, (iii) utilizing electric motors on select compressor applications, and (iv) utilizing methods to limit the release of methane gas during pipeline maintenance and operations.

EMPLOYEES

We 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 our interstate natural gas pipeline assets 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, 2008, we utilized the services of 1,136 full-time employees in addition to the other resources provided by ONEOK and its affiliates.

AVAILABLE INFORMATION

You can access financial and other information at our website at www.oneokpartners.com. We make available on our website, free of charge, copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the 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, Accounting and Financial Reporting Code of Ethics, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will make available, free of charge, copies of these documents upon request.

ITEM 1A. RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report on Form 10-K, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.

RISKS INHERENT IN OUR BUSINESS

The volatility of natural gas, crude oil and NGL prices could adversely affect our cash flow.

A significant portion of our revenues are derived from the sale of commodities received as payment for our natural gas gathering and processing services, for transportation and storage of natural gas and NGLs, and for the fractionation of NGLs. As a result, we are sensitive to commodity price fluctuations. Commodity prices have been and are likely to continue to be volatile in the future. High commodity prices and large commodity price spreads may not continue and could drop precipitously in a short period of time. Our commodity prices are subject to wide fluctuations in response to a variety of factors beyond our control, including the following:

15

Table of Contents

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 and related volumes could also decline.

We do not fully hedge against price changes in commodities. This could result in decreased revenues, increased costs and lower margins, adversely affecting our results of operations.

Our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil prices. Market risk refers to the risk of loss arising from adverse changes in commodity energy prices. Our primary exposure arises from commodity prices with respect to our processing agreements, the difference between NGL and natural gas prices with respect to our natural gas and NGL transportation, fractionation and exchange agreements, and the differential between the individual NGL products and NGLs in storage utilized by our natural gas liquids operations. To manage the risk from market fluctuations in natural gas, NGL and condensate prices, we use commodity derivative instruments such as futures contracts, swaps and options. However, we do not fully hedge against commodity price changes, and we therefore retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs.

Our use of financial instruments to hedge market risk may result in reduced income.

We utilize financial instruments to mitigate our exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce our exposure to interest rate fluctuations could expose us to risk of financial loss where we have contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit we would otherwise receive if we have contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate. Hedging arrangements that are used to reduce our exposure to commodity price fluctuations may limit the benefit we would otherwise receive if market prices for natural gas and NGLs exceed the stated price in the hedge instrument for these commodities.

Growing our business by constructing new pipelines and new processing and treating facilities or making modifications to our existing facilities subjects us to construction risks and risks that adequate natural gas or NGL supplies will not be available upon completion of the facilities.

One of the ways we intend to grow our business is through the construction of 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 requires the expenditure of significant amounts of capital, which may exceed our estimates, and involves numerous regulatory, environmental, political and legal uncertainties. Construction projects in our industry may increase demand on labor and material which may in turn impact our costs and schedule. If we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost. Additionally, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. We may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Additionally, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

16

Table of Contents

Our inability to execute growth and development projects and acquire new assets could reduce 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.

Our operations are subject to operational hazards and unforeseen interruptions, which could 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, earthquakes, floods or other similar events beyond our control. It is also possible that our infrastructure facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred, and interruptions to the operation of 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.

If the level of drilling and production in the Mid-Continent, Rocky Mountain and Gulf Coast regions substantially declines, our volumes and revenues could decline.

Our ability to maintain or expand our businesses depends largely on the level of drilling and production in the Mid-Continent, Rocky Mountain and Gulf Coast regions. Drilling and production are impacted by factors beyond our control, including:

In addition, drilling and production are impacted by environmental regulations governing water discharge. If the level of drilling and production in any of these regions substantially declines, our volumes and revenue could be reduced.

If production from the Western Canada Sedimentary Basin remains flat or declines and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for our interstate transportation services could significantly decrease.

We depend on natural gas supply from the Western Canada Sedimentary Basin because our interstate pipelines primarily transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S. market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and production remains flat or declines, demand for transportation service on our interstate natural gas pipelines could decrease significantly, which could adversely impact our results of operations.

Pipeline integrity programs and repairs may impose significant costs and liabilities.

In December 2003, the United States Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause us to

17

Table of Contents

incur significant capital and operating expenditures to make repairs or take remediation, preventive or mitigating actions that are determined to be necessary.

Our business is subject to increased regulatory oversight and potential penalties.

The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not be pursued by the FERC and U.S. Congress, especially in light of previous market power abuse by certain companies engaged in interstate commerce. In response to this issue, the U.S. Congress, in the Energy Policy Act of 2005 (EPACT), developed requirements intended to ensure that the energy market is not impacted by the exercise of market power or manipulative conduct. The FERC then adopted the Market Manipulation Rules to implement the authority granted under EPACT. These rules are intended to prohibit fraud and manipulation and are subject to broad interpretation. EPACT also gave the FERC increased penalty authority for violations.

Our regulated natural gas 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, interstate transportation rates must be just and reasonable and not unduly discriminatory. Under Northern Border Pipeline’s 2006 rate case settlement, there is a three-year moratorium preventing Northern Border Pipeline from filing rate cases and the participants from challenging Northern Border Pipeline’s rates, and a requirement that Northern Border Pipeline file a rate case within six years.

Our regulated pipeline companies have recorded certain assets that may not be recoverable from our customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.

Our operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:

Various governmental authorities, including the United States EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport and process, air emissions related to our operations, historical industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become

18

Table of Contents

necessary, some of which may be material. Additional information is included under Item 1, Business under “Environmental and Safety Matters” and in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might also adversely affect our products and activities, and federal and state agencies could impose additional safety requirements, all of which could materially affect our profitability.

In the competition for customers, we may have significant levels of uncontracted or discounted transportation capacity on our natural gas and natural gas liquids pipelines.

Our natural gas and natural gas liquids pipelines compete with other pipelines for natural gas and natural gas liquids supplies delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our pipelines, which could adversely impact our results of operations.

We are exposed to the credit risk of our customers, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our customers are predominantly producers, NGL end users and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their credit worthiness or ability to pay us for our services. We assess the credit worthiness of our customers and obtain security as we deem appropriate. If we fail to adequately assess the credit worthiness of existing or future customers, unanticipated deterioration in their credit worthiness and any resulting nonpayment and/or nonperformance could adversely impact our results of operations. In addition, if any of our customers file for bankruptcy protection, our results of operations may be negatively impacted.

RISKS INHERENT IN AN INVESTMENT IN US

The issuance of Class B units to ONEOK in connection with the acquisition of the ONEOK Energy Assets diluted our then current unitholders’ ownership interests.

In connection with the acquisition of the ONEOK Energy Assets, we issued approximately 36.5 million Class B limited partner units to ONEOK. The issuance of the Class B units decreased our then current common unitholders’ proportionate ownership interest in us. The Class B units are eligible to convert into common units on a one-for-one basis at ONEOK’s option due to approval of such conversion by our common unitholders at a special meeting of common unitholders held in March 2007.

In addition, ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and price that we deem appropriate.

ONEOK could withdraw the waiver of its right to receive, on its Class B units, 110 percent of the distributions paid with respect to our common units.

At a special meeting of the holders of our common units, adjourned to 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.

19

Table of Contents

If our unitholders vote to remove ONEOK or its affiliates as our general partner, quarterly distributions and distributions payable to ONEOK upon liquidation of the Class B units would increase.

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.

We do not operate all of our assets nor do we directly employ any of the persons responsible for providing us with administrative, operating and management services. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

We rely on ONEOK, ONEOK Services Company and ONEOK Partners GP to provide us with administrative, operating and management services. We have a limited ability to control our operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. ONEOK, ONEOK Services Company and ONEOK Partners GP may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should ONEOK, ONEOK Services Company and ONEOK Partners GP not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our contracts and negatively affect our business and operating results. Our reliance on ONEOK, ONEOK Services Company, and ONEOK Partners GP and the third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.

The Board of Directors of our general partner, our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.

ONEOK owns 100 percent of our general partner interest and a 43.7 percent limited partner interest in us. Although ONEOK, through the Board of Directors of our general partner, has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the Board of Directors of ONEOK has a fiduciary duty to manage our general partner in a manner beneficial to ONEOK. One member of the Board of Directors of our general partner is also a member of ONEOK’s Board of Directors. Conflicts of interest may arise between our general partner and its affiliates and between us and our unitholders. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders as long as it does not take action that conflicts with our Partnership Agreement or its limited fiduciary duties. These conflicts include, among others, the following situations:

20

Table of Contents

Our general partner and its affiliates may compete directly with us and have no obligation to present business opportunities to us.

ONEOK and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us.

Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:

By purchasing a common unit, a common unitholder will be bound by the provisions in our Partnership Agreement, including the provisions discussed above.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of our general partner from transferring its interest to a third party. The new members or unitholders, as the case may be, of our general partner would then be in a position to replace the directors of our general partner with their own choices and to control the decisions made by the Board of Directors of our general partner.

Any reduction in our credit ratings could materially and adversely affect our business, financial condition, liquidity and results of operations.

Our senior unsecured long-term debt has been assigned an investment grade rating by Moody’s of “Baa2” (Stable) and by S&P of “BBB” (Stable). We will seek to maintain an investment grade rating through prudent capital management and financing structures. However, we cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if Moody’s 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

21

Table of Contents

potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

A downgrade of our credit rating may require us to offer to repurchase certain of our senior notes or may impair our ability to access capital.

We could be required to offer to repurchase certain of our senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s or S&P rate those senior notes below investment grade (Baa3 for Moody’s and BBB- for S&P). Further, the indenture governing our senior notes due 2010 and 2011 includes an event of default upon acceleration of other indebtedness of $25 million or more and the indenture governing our senior notes due 2012, 2016, 2036 and 2037 includes an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable in full. 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 debt obligations.

As of December 31, 2007, we had total indebtedness of approximately $2.7 billion. Our indebtedness could have significant consequences. For example, it could:

If we are unable to meet our debt service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our notes and other indebtedness.

We and the Intermediate Partnership have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We and the Intermediate Partnership are holding companies, and our subsidiaries conduct all of our operations and own all of our operating assets. Neither we nor the Intermediate Partnership have significant assets other than the partnership interests and the equity in our subsidiaries and Northern Border Pipeline. As a result, our ability to make quarterly distributions and required payments on our indebtedness depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities, applicable state partnership laws, and other laws and regulations. If we are unable to obtain the funds necessary to make quarterly distributions or required payments on our indebtedness, we may be required to adopt one or more alternatives, such

22

Table of Contents

as refinancing the indebtedness or seeking alternative financing sources to fund the quarterly distributions and indebtedness payments.

We may issue additional common units without unitholder approval, which would dilute unitholders’ ownership interests.

Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units, subject to the limitations imposed by the NYSE. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon the sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our Partnership Agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

Our Partnership Agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.

Our Partnership Agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, cannot vote on any matter. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business. Unitholders may also have liability to repay distributions.

As a limited partner in a limited partnership organized under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if they participate in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. In addition, the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business.

TAX RISKS

Our tax treatment depends on our status as a partnership for federal income tax purposes. Additionally, we are only subject to entity level taxation in the state of Texas. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter.

23

Table of Contents

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and we likely would pay state taxes as well. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our common unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity level federal taxation. In addition, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, we became subject to a new entity level tax on the portion of our income generated in Texas beginning in 2007. Specifically, the Texas margin tax was imposed at a maximum effective rate of 0.7 percent of our gross income apportioned to Texas. Imposition of such tax on us by Texas, or any other state, reduces the cash available for distribution to our common unitholders.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and general partner.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the federal income tax positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may adversely impact the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact 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 result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

A unitholder may be required to pay taxes on a share of our income even if the unitholder does not receive any cash distributions from us.

A unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, whether or not the unitholder receives cash distributions from us. A unitholder may not receive cash distributions from us equal to the unitholder’s share of our taxable income or even equal to the actual tax liability that results from the unitholder’s share of our taxable income.

The taxable gain or loss on the disposition of our common units could be different than expected.

A unitholder will recognize a gain or loss on the sale of common units equal to the difference between the amount realized and the unitholder’s tax basis in those common units. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received plus the unitholder’s share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale. Prior distributions to a unitholder in excess of the total net taxable income allocated to a unitholder for a common unit, which decreased the tax basis in that common unit, will, in effect, become taxable income to a unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing a gain, may be ordinary income to a unitholder. Should the IRS successfully contest some positions we take, unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years.

Tax-exempt entities, regulated investment companies and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts, regulated investment companies known as mutual funds, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons may be subject to U.S. withholding taxes. Non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

24

Table of Contents

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

Unitholders will be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all United States federal, state and local tax returns and foreign tax returns, as applicable.

Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve the non-resident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our units.

The sale or exchange of 50 percent or more of the total interest in our capital and profits within a 12-month period will result in the termination of our Partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our limited partner units.

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.

Our treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.

Because we cannot match transferors and transferees of common units, we are required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. We do so by adopting certain depreciation conventions that do not conform to all aspects of the United States Treasury regulations. An IRS challenge to these conventions could adversely affect the tax benefits to a unitholder of ownership of the common units and

25

Table of Contents

could have a negative impact on their value or result in audit adjustments to our unitholders’ tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

Natural Gas Gathering and Processing

Our operations include gathering of raw natural gas production from oil and natural gas wells. We gather raw natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather raw natural gas in three producing basins in the Rocky Mountain region: (i) the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, (ii) the Powder River Basin of Wyoming and (iii) the Wind River Basin of Wyoming.

In the Mid-Continent and Rocky Mountain regions, raw natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and the unfractionated NGLs are extracted. In some cases, the unfractionated NGLs are separated at the processing facility into NGL products, through fractionation, and the NGL products are sold to refineries or local markets. The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to the end user. The unfractionated NGLs not sold in the local markets are delivered to natural gas liquids pipelines where they are transported, fractionated and delivered to the end user.

Our Natural Gas Gathering and Processing segment assets consist of the following:

Our natural gas processing operations utilize straddle and field gas processing plants to extract NGLs from raw natural gas and remove water vapor and other contaminants from the raw natural gas stream. A straddle gas processing plant is situated on a pipeline system and relies on the pipeline’s natural gas throughput volume, which subjects the plant to increased supply risk as it is dependent upon the throughput of a single pipeline rather than several supply sources. Field gas processing plants gather raw natural gas from multiple producing wells.

On January 1, 2007, the Bushton Plant was temporarily idled. Volumes available for processing at this straddle plant have declined due to contract terminations and natural field declines, which made it more efficient to process the remaining gas at other facilities. We have contracted for all of the capacity of the plant from ONEOK. We are in the process of adding new facilities at or near the plant, in conjunction with other changes that are being made to the plant. The plant currently has 1.0 Bcf/d processing capacity and 80 MBbl/d fractionation capacity. The plant and other nearby facilities are expected to resume operations in mid-2008, and will primarily provide natural gas liquids fractionation and storage services as a part of our Natural Gas Liquids Gathering and Fractionation segment.

Natural Gas Pipelines

Our Natural Gas Pipelines segment gathers and transports natural gas through regulated interstate and intrastate natural gas transmission pipelines, stores natural gas, and operates non-processable natural gas gathering facilities.

Our interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas pipelines in Montana, North Dakota, South Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission, OkTex Pipeline and a 50 percent interest in Northern Border Pipeline. Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee, and several interstate pipelines near Joliet, Illinois. Viking Gas Transmission transports natural gas from an interconnection with TransCanada near Emerson,

26

Table of Contents

Manitoba, to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin. Guardian Pipeline interconnects with several pipelines in Joliet, Illinois, and with a local distribution company in Ixonia, Wisconsin. OkTex Pipeline has interconnects in Oklahoma, New Mexico and Texas.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. In Texas, our intrastate pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. We also have intrastate pipelines that access the major natural gas producing area in south central Kansas.

Our storage assets include 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 has been idle since 2001 following natural gas explosions and eruptions of natural gas geysers in Hutchinson, Kansas. We began injecting brine into the facility in the first quarter of 2007 in order to ensure the long-term integrity of the facility. Monitoring of the facility and review of the data for the geoengineering study are ongoing.

Our Natural Gas Pipelines segment’s assets consist of the following:

Natural Gas Liquids Gathering and Fractionation

Our natural gas liquids gathering and fractionation assets consist of facilities that gather, fractionate and treat NGLs and store NGL purity products primarily in Oklahoma, Kansas and Texas, as well as store and fractionate NGLs in Mont Belvieu, Texas. Most of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from raw natural gas, are connected to our gathering systems. The natural gas liquids operations gather these unfractionated NGLs and deliver them to our fractionators. The unfractionated NGLs are then separated into NGL products, through a fractionation process, to realize the greater economic value of the NGL products. The individual NGL products are then stored or distributed to petrochemical manufacturers, refineries and propane distributors. Our fractionation and storage facilities are connected to the key natural gas liquids market centers in Conway, Kansas, and Mont Belvieu, Texas, by FERC-regulated interstate natural gas liquids pipelines, which are part of our Natural Gas Liquids Pipelines segment.

Our Natural Gas Liquids Gathering and Fractionation segment assets consist of the following:

Natural Gas Liquids Pipelines

Our natural gas liquids gathering pipelines deliver unfractionated NGLs gathered in Oklahoma, Kansas and the Texas panhandle to our Mid-Continent fractionation facilities in Medford, Oklahoma. Our natural gas liquids distribution pipelines deliver NGL products to the natural gas liquids market hubs in Conway, Kansas, and Mont Belvieu, Texas. Through our acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan, we acquired terminal and storage facilities as well as natural gas liquids and refined petroleum products pipelines that connect our Mid-Continent assets with the Midwest markets near Chicago, Illinois. We operate FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Nebraska, Missouri, Iowa, Illinois and Texas. We have natural gas liquids terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.

27

Table of Contents

Our Natural Gas Liquids Pipelines segment’s assets consist of the following:

Other

Our Other segment includes Black Mesa, which is a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona, and terminates at Mohave in Laughlin, Nevada. We plan to either divest the Black Mesa pipeline or commence decommissioning of the pipeline during 2008.

ITEM 3. LEGAL PROCEEDINGS

Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”). Plaintiffs brought suit on May 28, 1999, against Mid-Continent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), as well as approximately 225 other defendants. Plaintiffs sought class certification for its claims for monetary damages that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the Court refused to certify the class sought by plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to undermeasurement of volumes. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.

Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”). This action was filed by the plaintiffs on May 12, 2003, after the Court had denied class status in Price I. Plaintiffs are seeking monetary damages based upon a claim that 21 groups of defendants, including Mid-Continent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

28

Table of Contents

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION AND HOLDERS

Our equity consists of a 2 percent general partner interest and a 98 percent limited partner interest. Our limited partner interests are represented by our common units, which are listed on the NYSE under the trading symbol “OKS,” and our Class B limited partner units. The following table sets forth the high and low closing prices of our common units for the periods indicated.

At February 20, 2008, there were 902 holders of record of our 46,397,214 outstanding common units.

CASH DISTRIBUTIONS

The following table sets forth the quarterly cash distribution declared and paid on our common and Class B units during the periods indicated.

In January 2008, we increased our cash distribution to $1.025 per unit for the fourth quarter of 2007, which was paid on February 14, 2008, to unitholders of record as of January 31, 2008.

CASH DISTRIBUTION POLICY

Under our Partnership Agreement, we make distributions to our partners with respect to each calendar quarter in an amount equal to 100 percent of available cash within 45 days following the end of each quarter. Available cash generally consists of our cash receipts adjusted for our cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to our general partner. As an incentive, our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, our general partner receives:

We paid cash distributions to our general and limited partners of $384.6 million for 2007 and $265.5 million for 2006, which included an incentive distribution to our general partner of $47.1 million for 2007 and $23.1 million for 2006. 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.

29

Table of Contents

ISSUANCE OF CLASS B UNITS

In April 2006, we issued approximately 36.5 million Class B units to ONEOK as part of the acquisition of the ONEOK Energy Assets. See the discussion of the ONEOK Energy Assets acquisition in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation under “Significant Acquisitions and Divestitures.” The units issued to ONEOK were the newly created Class B limited partner units. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on our common units and generally have the same voting rights as our common units. See Note B of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

The Class B units were not registered in reliance on the exemption from registration with the SEC as set forth in Section 4(2) of the Securities Act of 1933, as amended, as a transaction not involving any public offering.

PERFORMANCE GRAPH

The following performance graph compares the performance of our common units with the S&P 500 Index and the Alerian MLP Index during the period beginning on December 31, 2002, and ending on December 31, 2007. 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.

30

Table of Contents

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for each of the periods indicated.

Financial data for 2007 and 2006 is not directly comparable with 2005, 2004 and 2003 due to the significance of the April 2006 ONEOK Transactions. See discussion of acquisitions and dispositions beginning on page 32 under “Significant Acquisitions and Divestitures” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

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 on Form 10-K.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us this past year. Please refer to the Financial and Operating Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Financial Statements for a complete explanation of the following items.

In July 2007, we announced a series of organizational changes that led to the realignment of our previous business segments. Our financial results are now reported in these four segments: (i) Natural Gas Gathering and Processing, which remains unchanged, (ii) Natural Gas Pipelines, which is comprised of our former interstate natural gas pipelines segment and the natural gas assets of our former pipelines and storage segment, (iii) Natural Gas Liquids Gathering and Fractionation, which remains unchanged, and (iv) Natural Gas Liquids Pipelines, which is comprised of the natural gas liquids assets of our former pipelines and storage segment. Prior periods have been restated to reflect these segment changes. The change reflects the increasing scale of the natural gas liquids business, which has grown significantly since 2006. Our natural gas liquids business is expanding as we integrate the assets acquired in October 2007 from a subsidiary of Kinder Morgan into our Natural Gas Liquids Pipelines segment and complete our other internal growth projects.

In September 2007, we completed an underwritten public debt offering of $600 million to finance the assets acquired from Kinder Morgan and to repay debt outstanding under the 2007 Partnership Credit Agreement, which was incurred to fund our internal growth capital projects. Both the assets acquired from Kinder Morgan and our capital projects are discussed below in the “Significant Acquisitions and Divestitures” and the “Capital Projects” sections.

On January 15, 2008, we declared a cash distribution of $1.025 per unit ($4.10 per unit on an annualized basis), an increase of approximately 5 percent over the $0.98 declared in January 2007.

Net income per unit decreased to $4.21 in 2007, compared with $5.01 in 2006. The decrease in net income per unit for the year is primarily due to the gain on sale of a 20 percent partnership interest in Northern Border Pipeline in the second quarter of 2006. Operating income decreased to $446.8 million in 2007, compared with $511.2 million in 2006. Excluding the gain on sale of assets, operating income increased to $444.8 million in 2007 compared with $395.7 million in 2006. Our Natural Gas Liquids Gathering and Fractionation segment and Natural Gas Liquids Pipelines segment benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold. In addition, we benefited from higher product price spreads and higher isomerization price spreads in our Natural Gas Liquids Gathering and Fractionation segment. Our Natural Gas Liquids Pipelines segment benefited from the incremental operating income related to the assets

31

Table of Contents

acquired from Kinder Morgan in October 2007. These increases were partially offset by decreased natural gas transportation margins in our Natural Gas Pipelines segment, primarily resulting from lower throughput and higher fuel costs. Operating income also decreased in our Natural Gas Gathering and Processing segment, primarily due to lower natural gas volumes processed as a result of contract terminations in late 2006.

SIGNIFICANT ACQUISITIONS AND DIVESTITURES

Acquisition of NGL Pipeline - In October 2007, we completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of three refined products terminals and connecting pipelines. Financing for this transaction came from the proceeds of our September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion on the 2037 Notes. These assets are included in our Natural Gas Liquids Pipelines segment.

ONEOK Transactions - In April 2006, we completed the acquisition and consolidated certain companies comprising ONEOK’s former gathering and processing, natural gas liquids, and pipelines and storage segments (collectively, the ONEOK Energy Assets) in a series of transactions (collectively, the ONEOK Transactions). This acquisition is accounted for in our Natural Gas Gathering and Processing, Natural Gas Pipelines, Natural Gas Liquids Gathering and Fractionation, and Natural Gas Liquids Pipelines segments.

Acquisition of ONEOK Energy Assets - We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units, which, when combined with its general partner interest, increased its total interest in us to approximately 45.7 percent. We used $1.05 billion drawn under our $1.1 billion, 364-day credit agreement (the Bridge Facility), coupled with the proceeds from the sale of a 20 percent partnership interest in Northern Border Pipeline, to finance the cash portion of the transaction. The assets were recorded at historical cost rather than at fair value since these transactions were between affiliates under common control. These assets and their related operations are included in our consolidated financial statements retroactive to January 1, 2006.

Equity Issuance - In connection with the ONEOK Transactions, we amended our Partnership Agreement to provide for the issuance of Class B limited partner units and issued approximately 36.5 million Class B limited partner units to ONEOK. The Class B limited partner units were issued on April 6, 2006. For more information regarding the Class B units, refer to discussion of the ONEOK Transactions in Note B of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Purchase and Sale of General Partner Interest - In April 2006, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. As a result, ONEOK now owns our entire 2 percent general partner interest and controls us.

Disposition of 20 Percent Partnership Interest in Northern Border Pipeline - In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became the operator of the pipeline in April 2007. Effective January 1, 2006, our interest in Northern Border Pipeline is accounted for as an investment under the equity method in our Natural Gas Pipelines segment.

Acquisition of Guardian Pipeline Interests - In April 2006, we acquired the 66- ²/3 percent interest in Guardian Pipeline not previously owned by us for approximately $77 million, increasing our ownership interest to 100 percent. We used borrowings from our credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Guardian Pipeline is consolidated in our consolidated financial statements and reported in our Natural Gas Pipelines segment as of January 1, 2006.

32

Table of Contents

Capital Projects

Woodford Shale Natural Gas Liquids Pipeline Extension - In February 2008, we announced plans to construct a 78-mile natural gas liquids gathering pipeline to connect two natural gas processing plants in the Woodford Shale area in southeast Oklahoma at a cost of approximately $25 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. These two plants are expected to produce approximately 25 MBbl/d of unfractionated NGLs. Until the Arbuckle Pipeline project is completed, the natural gas liquids production will be transported by our existing Mid-Continent natural gas liquids pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported to our Mont Belvieu, Texas, fractionation facility. This project will be in our Natural Gas Liquids Gathering and Fractionation segment.

Overland Pass Pipeline Company - In May 2006, we entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company is building a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs, which can be increased to approximately 150 MBbl/d with additional pump facilities. During 2006, we paid $11.6 million to Williams for the acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. As the 99 percent owner of the joint venture, we will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have the option to increase its ownership up to 50 percent by reimbursing us for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. This project has received the required approvals of various state and federal regulatory authorities, and we are constructing the pipeline with start-up currently scheduled for the second quarter of 2008.

As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $535 million, excluding AFUDC. Since our initial estimate in early 2006, there has been a significant increase in the demand for pipeline construction-related services, which has led to higher rates, particularly for construction labor and equipment. Additionally, due to the extended permitting process, we are constructing the pipeline during the winter months, which could contribute to added construction costs and could cause further delays. The severity of the winter conditions could further impact our cost and schedule estimates. In addition, we are investing approximately $216 million, excluding AFUDC, to expand our existing fractionation and storage capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. Overland Pass Pipeline Company is included in our Natural Gas Liquids Pipelines segment, while the associated expansions are included in our Natural Gas Liquids Gathering and Fractionation segment and Natural Gas Liquids Pipelines segment.

Piceance Lateral Pipeline - In March 2007, we announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be transported by the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required state and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the second quarter of 2009, at a current cost estimate of approximately $120 million, excluding AFUDC. This project is in our Natural Gas Liquids Pipelines segment.

Arbuckle Pipeline Natural Gas Liquids Pipeline - In March 2007, we announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast, at a current estimated cost of approximately $260 million, excluding AFUDC. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquids and will connect our existing Mid-Continent infrastructure with our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. Construction of the pipeline will require permits from various federal, state and local regulatory bodies. Construction is currently expected to begin in mid-2008 and be completed by early 2009. This project is in our Natural Gas Liquids Pipelines segment.

Williston Basin Gas Processing Plant Expansion - In March 2007, we announced the expansion of our Grasslands natural gas processing facility in North Dakota at a cost of approximately $30 million, excluding AFUDC. The Grasslands facility is our largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8

33

Table of Contents

MBbl/d. The expansion project is expected to come on-line in phases, with the final phase currently expected to be on-line in the third quarter of 2008. This project is in our Natural Gas Gathering and Processing segment.

Fort Union Gas Gathering Expansion - In January 2007, Fort Union Gas Gathering announced that it will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. The expansion is expected to cost approximately $110 million, excluding AFUDC, which will be financed within the Fort Union Gas Gathering partnership and will occur in two phases. Phase 1, with more than 200 MMcf/d capacity, was placed in service during the fourth quarter of 2007. Phase 2, with approximately 450 MMcf/d capacity, is currently expected to be in service during the second quarter of 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. We own approximately 37 percent of Fort Union Gas Gathering. This investment is in our Natural Gas Gathering and Processing segment and is accounted for under the equity method of accounting.

Guardian Pipeline Expansion and Extension - In December 2007, Guardian Pipeline received and accepted the certificate of public convenience and necessity issued by the FERC for its expansion and extension project. The certificate authorizes us to construct, install and operate approximately 119 miles of a 20-inch and 30-inch natural gas transportation pipeline with a capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin, to the Green Bay, Wisconsin, area. The project is supported by long-term shipper commitments. The cost of the project is currently estimated to be $260 million, excluding AFUDC. The pipeline is currently projected to be in service in the fourth quarter of 2008. This project is in our Natural Gas Pipelines segment.

Midwestern Gas Transmission Eastern Extension - Midwestern Gas Transmission’s eastern extension pipeline was placed into service in January 2008. The extension added approximately 31 miles of natural gas transportation pipeline, with a capacity to transport 120 MMcf/d of natural gas from Midwestern’s previous terminus at Portland, Tennessee, to interconnects with Columbia Gulf Transmission Company and East Tennessee Natural Gas, LLC, near Hartsville, Tennessee. The project is supported by a long-term shipper commitment. Total capital expenditures are expected to be $62 million, excluding AFUDC. This project is in our Natural Gas Pipelines segment.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of Statement 157, “Fair Value Measurements,” Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” Statement 141R, “Business Combinations,” and Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from our estimates.

The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.

Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

We assess our goodwill and intangible assets for impairment at least annually, based on Statement 142, “Goodwill and Other Intangible Assets.” There were no impairment charges resulting from the July 1, 2007, impairment tests and no events indicating an impairment have occurred subsequent to that date. An initial assessment is made by comparing the fair value of

34

Table of Contents

the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. At December 31, 2007, we had $394.6 million of goodwill recorded on our Consolidated Balance Sheet as shown below.

Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. As shown below, we had $287.5 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2007.

During 2006, we reassessed our coal slurry pipeline operation and concluded that the likelihood of Black Mesa resuming operations was significantly reduced, and a goodwill and asset impairment of $8.4 million and $3.6 million, respectively, was recorded as depreciation and amortization. The reduction to our net income after income taxes was $10.6 million. Additional information about Black Mesa is included above in Item 1 under “Description of Business Segments - Other.”

Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million as of December 31, 2007 and 2006. These amounts were recorded in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and under Statement 142 is not subject to amortization but rather to impairment testing pursuant to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The impairment test under APB Opinion No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with APB Opinion No. 18. See Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of unconsolidated affiliates.

We do not currently anticipate any additional goodwill or asset impairments to occur within the next year, but if such events were to occur over the long term, the impact could be significant to our financial condition and results of operations.

Derivatives and Risk Management - We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve more predictable cash flows. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of a derivative instrument is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

Market value changes result in a change in the fair value of our derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the nature of the risk being hedged and how we will determine if the hedging instrument is effective. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain

35

Table of Contents

or loss in a given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collars or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, condensate, and fuel requirements. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flow. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) and subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.

Upon election, many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.

See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more discussion of derivatives and risk management activities.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of contingencies.

FINANCIAL AND OPERATING RESULTS

Consolidated Operations

Selected Financial Information - The following table sets forth certain selected financial information for the periods indicated.

Operating Results - Net margin increased for 2007, compared with 2006, primarily due to the performance of our Natural Gas Liquids Gathering and Fractionation segment and Natural Gas Liquids Pipelines segment, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold. In addition, net margin increased due to higher product price spreads and higher isomerization price spreads in our Natural Gas Liquids Gathering and Fractionation segment. Our Natural Gas Liquids Pipelines segment benefited from the incremental net margin related to the acquired assets from Kinder Morgan in October 2007. Net margin also increased due to increased storage margins in our Natural Gas Pipelines segment. These increases were partially offset by decreased natural gas transportation margins in our Natural Gas Pipelines segment, primarily resulting from lower throughput and higher fuel costs. Net margin also decreased

36

Table of Contents

in our Natural Gas Gathering and Processing segment, primarily due to lower natural gas volumes processed as a result of contract terminations in late 2006.

Operating costs increased for 2007, compared with 2006, primarily due to higher employee-related costs and the incremental operating expenses associated with our acquired assets from Kinder Morgan, partially offset by lower litigation costs.

Depreciation and amortization decreased for 2007, compared with 2006, primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa, which is included in our Other segment.

Gain on sale of assets decreased for 2007, compared with 2006, primarily due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our Natural Gas Pipelines segment.

Equity earnings from investments for 2007 and 2006 primarily include earnings from our interest in Northern Border Pipeline. The decrease in equity earnings from investments for 2007 is primarily due to the decrease in our share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 32 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.

Allowance for equity funds used during construction increased for 2007, compared with 2006, due to our capital projects, which are discussed beginning on page 33.

Minority interest in income of consolidated subsidiaries decreased for 2007, compared with 2006, primarily due to our acquisition of the remaining interest in Guardian Pipeline. Minority interest in income of consolidated subsidiaries for 2006 included the 66- ²/3 percent interest in Guardian Pipeline that we did not own until April 2006. We owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006.

Net margin was $843.5 million in 2006, compared with $493.9 million in 2005. Net margin increased primarily due to the acquisition of the ONEOK Energy Assets, which accounts for $638.9 million of our consolidated net margin for the period, and, to a lesser extent, the effect of the Guardian Pipeline consolidation, partially offset by the effect of the Northern Border Pipeline deconsolidation.

Operating costs increased in 2006, compared with 2005, primarily due to our acquisition of the ONEOK Energy Assets.

Equity earnings from investments for 2006 primarily consisted of earnings from our interest in Northern Border Pipeline which is no longer consolidated as of January 1, 2006. Equity earnings from investments for 2005 consisted of earnings from our 33- ¹/3 percent interest in Guardian Pipeline, which is reflected on a consolidated basis beginning January 1, 2006.

Minority interest in net income for 2006 included earnings from the 66- ²/3 percent interest in Guardian Pipeline until that interest was acquired by us in April 2006. Minority interest in net income for 2005 included earnings from the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipeline’s results were consolidated.

More information regarding our results of operations is provided in the following discussion of operating results for each of our segments.

37

Table of Contents

Natural Gas Gathering and Processing

Acquisition - In April 2006, we completed the acquisition of the ONEOK Energy Assets, which is discussed further on page 32.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Natural Gas Gathering and Processing segment for the periods indicated.

38

Table of Contents

Operating Results - Net margin decreased $4.3 million for 2007, compared with 2006, primarily due to the following:

Operating costs decreased $12.1 million for 2007, compared with 2006, primarily due to lower litigation costs and reduced operating expenses associated with the temporarily idled Bushton Plant, partially offset by higher employee-related costs.

Depreciation and amortization and capital expenditures increased for 2007, compared with 2006, primarily due to increased depreciation expense associated with our capital projects, which are discussed beginning on page 33.

The increase in equity earnings from investments for 2007, compared with 2006, is driven primarily by the earnings related to our interest in an investment in Venice Energy Services Co., LLC which operated on a limited basis in 2006 due to hurricane damage.

Net margin increased $275.5 million in 2006, compared with 2005, primarily due to the following:

Our Natural Gas Gathering and Processing segment is exposed to commodity price risk, primarily from NGLs, as a result of our contractual obligations for services provided. A small percentage of our services are provided through keep-whole arrangements. Our realized gross processing spread for 2007 was above the five-year average of $3.58 per MMBtu. See discussion regarding our commodity price risk beginning on page 51 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

39

Table of Contents

Natural Gas Pipelines

Acquisition and Divestiture - The following transactions are described beginning on page 32.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Natural Gas Pipelines segment for the periods indicated.

Operating Results - Net margin decreased $5.7 million for 2007, compared with 2006, due to the following:

Operating costs increased $5.1 million for 2007, compared with 2006, primarily due to higher employee-related costs.

Equity earnings from investments for 2007 and 2006 primarily include earnings from our interest in Northern Border Pipeline. The decrease in equity earnings from investments of $10.3 million for 2007, compared with 2006, is primarily due to the decrease in our share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 32 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.

The increase in capital expenditures for 2007, compared with 2006, is driven primarily by our capital projects, which are discussed beginning on page 33.

40

Table of Contents

Net margin decreased $127.3 million for 2006, compared with 2005, due to the following:

Depreciation and amortization decreased $34.4 million for 2006, compared with 2005, due to a decrease of $58.1 million related to Northern Border Pipeline, which is no longer consolidated as of January 1, 2006, offset by an increase of $5.9 million due to the consolidation of Guardian Pipeline and $17.8 million due to acquiring assets from ONEOK.

During the second quarter of 2006, we sold a 20 percent partnership interest in Northern Border Pipeline and recorded a gain on sale of approximately $113.9 million.

The increase in equity earnings from investments of $70.6 million for 2006, compared with 2005, is primarily due to our interest in Northern Border Pipeline, which is no longer consolidated as of January 1, 2006. Equity earnings from investments of $2.3 million for 2005 were primarily due to our 33- ¹/ 3 percent interest in Guardian Pipeline, which is reflected on a consolidated basis beginning January 1, 2006.

Minority interest in income of consolidated subsidiaries for 2006 included the 66- ²/3 percent interest in Guardian Pipeline until that interest was acquired by us in April 2006. Minority interest in net income for 2005 included earnings from the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipeline’s results were consolidated.

The increase in capital expenditures for 2006, compared with 2005, is primarily due to the assets acquired from ONEOK.

Natural Gas Liquids Gathering and Fractionation

Acquisition - In April 2006, we completed the acquisition of the ONEOK Energy Assets, which is discussed further on page 32. We did not have a Natural Gas Liquids Gathering and Fractionation segment prior to 2006.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Natural Gas Liquids Gathering and Fractionation segment for the periods indicated.

41

Table of Contents

Operating Results - Net margin increased $38.8 million for 2007, compared with 2006, due to the following:

Operating costs increased for 2007, compared with 2006, primarily due to higher regulatory compliance costs at our storage facilities, employee-related costs and general taxes, as well as the acquisition of the Mont Belvieu storage assets in the fourth quarter of 2006.

The increase in capital expenditures for 2007, compared with 2006, is driven primarily by our growth activities for new supply connections. See discussion of our capital projects beginning on page 33.

Natural Gas Liquids Pipelines

Acquisitions - The following acquisitions are described beginning on page 32.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating results for our Natural Gas Liquids Pipelines segment for the periods indicated.

Operating Results - Net margin increased $21.0 million for 2007, compared with 2006, primarily as a result of: