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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)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 93-1120873                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
|                                                               | 
|100 West Fifth Street, Tulsa, OK                               |  | 74103-2498                          
|(Address of principal executive offices)                       |  | (Zip Code)                          

Registrants telephone number, including area code (918) 588-7000

Securities registered pursuant to Section 12(b) of the Act:



|                      |  |                                            
|--------------------- |  | -------------------------------------------
|Common units          |  | New York Stock Exchange                    
|(Title of Each Class) |  | (Name of Each Exchange on which Registered)

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.



|              |  |  |  |                                 
|------------- |  |  |  | --------------------------------
|Class         |  |  |  | Outstanding at February 20, 2008
|Common units  |  |  |  | 46,397,214 units                
|Class B units |  |  |  | 36,494,126 units                



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ONEOK PARTNERS, L.P.

2007 ANNUAL REPORT ON FORM 10-K



|           |  |                                                                                                              |  |         
|---------- |  | ------------------------------------------------------------------------------------------------------------ |  | --------
|Part I.    |  |                                                                                                              |  | Page No.
|           |  |                                                                                                             
|Item 1.    |  | Business                                                                                                     |  | 5-15    
|           |  |                                                                                                             
|Item 1A.   |  | Risk Factors                                                                                                 |  | 15-26   
|           |  |                                                                                                             
|Item 1B.   |  | Unresolved Staff Comments                                                                                    |  | 26      
|           |  |                                                                                                             
|Item 2.    |  | Properties                                                                                                   |  | 26-28   
|           |  |                                                                                                             
|Item 3.    |  | Legal Proceedings                                                                                            |  | 28      
|           |  |                                                                                                             
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                                          |  | 28      
|           |  |                                                                                                             
|Part II.   |  |                                                                                                              |  |         
|           |  |                                                                                                             
|Item 5.    |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 29-30   
|           |  |                                                                                                             
|Item 6.    |  | Selected Financial Data                                                                                      |  | 31      
|           |  |                                                                                                             
|Item 7.    |  | Managements Discussion and Analysis of Financial Condition and Results of Operation                         |  | 31-50   
|           |  |                                                                                                             
|Item 7A.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                   |  | 50-52   
|           |  |                                                                                                             
|Item 8.    |  | Financial Statements and Supplementary Data                                                                  |  | 53-82   
|           |  |                                                                                                             
|Item 9.    |  | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure                         |  | 82      
|           |  |                                                                                                             
|Item 9A.   |  | Controls and Procedures                                                                                      |  | 82-83   
|           |  |                                                                                                             
|Item 9B.   |  | Other Information                                                                                            |  | 83      
|           |  |                                                                                                             
|Part III.  |  |                                                                                                              |  |         
|           |  |                                                                                                             
|Item 10.   |  | Directors, Executive Officers and Corporate Governance                                                       |  | 83-87   
|           |  |                                                                                                             
|Item 11.   |  | Executive Compensation                                                                                       |  | 87-94   
|           |  |                                                                                                             
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters               |  | 95      
|           |  |                                                                                                             
|Item 13.   |  | Certain Relationships and Related Transactions, and Director Independence                                    |  | 95-98   
|           |  |                                                                                                             
|Item 14.   |  | Principal Accounting Fees and Services                                                                       |  | 98-99   
|           |  |                                                                                                             
|Part IV.   |  |                                                                                                              |  |         
|           |  |                                                                                                             
|Item 15.   |  | Exhibits, Financial Statement Schedules                                                                      |  | 99-103  
|           |  |                                                                                                             
|Signatures |  |                                                                                                              |  | 104     

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.



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GLOSSARY

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



|                               |  |                                                                                                                                                                       
|------------------------------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|AFUDC                          |  | Allowance for funds used during construction                                                                                                                          
|APB Opinion                    |  | Accounting Principles Board Opinion                                                                                                                                   
|ARB                            |  | Accounting Research Bulletin                                                                                                                                          
|Bbl                            |  | Barrels, 1 barrel is equivalent to 42 United States gallons                                                                                                           
|Bbl/d                          |  | Barrels per day                                                                                                                                                       
|BBtu/d                         |  | Billion British thermal units per day                                                                                                                                 
|Bcf                            |  | Billion cubic feet                                                                                                                                                    
|Bcf/d                          |  | Billion cubic feet per day                                                                                                                                            
|Bighorn Gas Gathering          |  | Bighorn Gas Gathering, L.L.C.                                                                                                                                         
|Black Mesa                     |  | Black Mesa Pipeline, Inc.                                                                                                                                             
|Btu                            |  | British thermal units, a measure of the amount of heat required to raise the temperature of one pound of water one degree
Fahrenheit                                  
|Bushton Plant                  |  | Bushton Gas Processing Plant                                                                                                                                          
|EITF                           |  | Emerging Issues Task Force                                                                                                                                            
|EPA                            |  | United States Environmental Protection Agency                                                                                                                         
|Exchange Act                   |  | Securities Exchange Act of 1934, as amended                                                                                                                           
|FASB                           |  | Financial Accounting Standards Board                                                                                                                                  
|FERC                           |  | Federal Energy Regulatory Commission                                                                                                                                  
|FIN                            |  | FASB Interpretation                                                                                                                                                   
|Fort Union Gas Gathering       |  | Fort Union Gas Gathering, L.L.C.                                                                                                                                      
|GAAP                           |  | Generally Accepted Accounting Principles in the United States                                                                                                         
|Guardian Pipeline              |  | Guardian Pipeline, L.L.C.                                                                                                                                             
|Heartland                      |  | Heartland Pipeline Company                                                                                                                                            
|Intermediate Partnership       |  | ONEOK Partners Intermediate Limited Partnership, formerly known as Northern Border Intermediate Limited Partnership, a wholly owned
subsidiary of ONEOK Partners, L.P.
|IRS                            |  | Internal Revenue Service                                                                                                                                              
|KCC                            |  | Kansas Corporation Commission                                                                                                                                         
|KDHE                           |  | Kansas Department of Health and Environment                                                                                                                           
|LIBOR                          |  | London Interbank Offered Rate                                                                                                                                         
|Lost Creek Gathering Company   |  | Lost Creek Gathering Company, L.L.C                                                                                                                                   
|MBbl                           |  | Thousand barrels                                                                                                                                                      
|MBbl/d                         |  | Thousand barrels per day                                                                                                                                              
|Midwestern Gas Transmission    |  | Midwestern Gas Transmission Company                                                                                                                                   
|MMBtu                          |  | Million British thermal units                                                                                                                                         
|MMBtu/d                        |  | Million British thermal units per day                                                                                                                                 
|MMcf                           |  | Million cubic feet                                                                                                                                                    
|MMcf/d                         |  | Million cubic feet per day                                                                                                                                            
|Moodys                        |  | Moodys Investors Service, Inc.                                                                                                                                       
|NBP Services                   |  | NBP Services, LLC, a subsidiary of ONEOK                                                                                                                              
|NGL(s)                         |  | Natural gas liquid(s)                                                                                                                                                 
|Northern Border Pipeline       |  | Northern Border Pipeline Company                                                                                                                                      
|NYMEX                          |  | New York Mercantile Exchange                                                                                                                                          
|NYSE                           |  | New York Stock Exchange                                                                                                                                               
|OBPI                           |  | ONEOK Bushton Processing Inc.                                                                                                                                         
|OCC                            |  | Oklahoma Corporation Commission                                                                                                                                       
|OkTex Pipeline                 |  | OkTex Pipeline Company, L.L.C.                                                                                                                                        
|ONEOK                          |  | ONEOK, Inc.                                                                                                                                                           
|ONEOK NB                       |  | ONEOK NB Company, formerly known as Northwest Border Pipeline Company, a wholly owned subsidiary of ONEOK, Inc.                                                       
|ONEOK Partners GP              |  | ONEOK Partners GP, L.L.C., formerly known as Northern Plains Natural Gas Company, LLC, a wholly owned subsidiary of ONEOK, Inc. and our
sole general partner          
|Overland Pass Pipeline Company |  | Overland Pass Pipeline Company LLC                                                                                                                                    
|Partnership Agreement          |  | Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P.                                                                                   



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|                        |  |                                                                                
|----------------------- |  | -------------------------------------------------------------------------------
|POP                     |  | Percent of Proceeds                                                            
|RRC                     |  | Texas Railroad Commission                                                      
|S&P                     |  | Standard & Poors Rating Group                                                 
|SEC                     |  | Securities and Exchange Commission                                             
|Statement               |  | Statement of Financial Accounting Standards                                    
|TC PipeLines            |  | TC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP
|TransCanada             |  | TransCanada Corporation                                                        
|Viking Gas Transmission |  | Viking Gas Transmission Company                                                

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.



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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:

| |  |  | our Natural Gas Gathering and Processing segment primarily gathers and processes raw natural gas;
| | - |  | -------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs and stores and markets NGL products; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Liquids Pipelines segment primarily operates our FERC-regulated interstate natural gas liquids gathering and distribution pipelines.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------

For financial and statistical information regarding our business segments, see Item 7, Managements Discussion and Analysis of
Financial Condition and Results of Operation. See Note 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-



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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



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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.

| |  |  | Percent of Proceeds (POP) - Under a POP contract, we retain a percentage of the NGLs and/or a percentage of the residue gas as payment for gathering, compressing
and processing the producers raw natural gas. The producer may take its share of the NGLs and residue gas in kind or receive its share of proceeds from our sale of the commodities. POP contracts expose us to both natural gas and NGL commodity
price risk, but economically align us with the producer because we both benefit from higher commodity prices. There are a variety of factors that directly affect our POP margins, including:
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the percentages of products retained that represent our equity NGL, condensate and residue gas sales volumes,
| | - |  | -------------------------------------------------------------------------------------------------------------

| |  |  | transportation and fractionation costs incurred on the NGLs, and
| | - |  | ----------------------------------------------------------------

| |  |  | the natural gas, crude oil and NGL prices received for our retained products.
| | - |  | -----------------------------------------------------------------------------

| |  |  | Fee - Under a fee contract, we are paid a fee for the services provided on a basis such as Btus gathered, compressed and/or processed. The wellhead volume and fees
received for the services provided are the main components of the margin for this type of contract. The producer may take its NGLs and residue gas in kind or receive its proceeds from our sale of the commodities. This type of contract primarily
exposes us to volumetric risk with minimal commodity price risk, as a result of fuel costs and the value of the retained fuel. Our POP and keep-whole contracts also typically include fee provisions.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Keep-Whole - Under a keep-whole processing contract, we extract NGLs from the raw natural gas and return to the producer volumes of residue gas containing the same
amount of Btus as the raw natural gas that was delivered to us.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of residue gas to replace the Btus
that were removed as NGLs through the gathering and processing operation, commonly referred to as shrink. Under index-based purchase agreements, we purchase raw natural gas at the wellhead to replace the natural gas that we consume in
processing, and we typically bear the full cost of the plant fuel and shrink, with the excess residue gas being sold monthly at index-based prices. By using this contract type, the producer is kept whole on a Btu basis. This type of contract exposes
us to the keep-whole spread, or gross processing spread, which is the relative difference in the economic value between NGLs and natural gas on a Btu basis. The main factors that affect our keep-whole margins include:
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | shrink,
| | - |  | -------

| |  |  | plant fuel consumed,
| | - |  | --------------------

| |  |  | transportation and fractionation costs incurred on the NGLs,
| | - |  | ------------------------------------------------------------

| |  |  | gross processing spread, and
| | - |  | ----------------------------

| |  |  | the natural gas, crude oil and NGL prices received for products sold.
| | - |  | ---------------------------------------------------------------------

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



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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



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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.

| |  |  | Firm Service - Customers can reserve a fixed quantity of pipeline or storage capacity for the term of their contract. Under this type of contract, the customer pays
a fixed fee for a specified quantity regardless of their actual usage. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store and/or we may retain a
specified volume of natural gas in-kind for fuel. Under the firm service contract, the customer is generally guaranteed access to the capacity they reserve.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Interruptible Service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm service requests are
satisfied or on an as-available basis. Interruptible service customers are typically assessed fees, such as a commodity charge, based on their actual usage and/or we may retain a specified volume of natural gas in-kind for fuel. Under the
interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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.



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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.

| |  |  | Our exchange services business collects fees to gather, fractionate and treat unfractionated NGLs thereby converting them into NGL products that are stored and
shipped to a market center or customer-designated location.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our optimization business utilizes our asset base, contract portfolio and market knowledge to capture locational and seasonal price spreads. We move NGL products
between Conway, Kansas, and Mont Belvieu, Texas, in order to capture the locational price spreads between the two market centers. Our NGL storage facilities in the Mid-Continent and Gulf Coast regions are used to capture seasonal price variances.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our isomerization business captures the price spread when normal butane is converted into the more valuable iso-butane at an isomerization unit in Conway, Kansas.
Iso-butane is used in the refining industry to upgrade the octane of motor gasoline.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our storage business collects fees to store NGLs in Conway, Kansas, and Mont Belvieu, Texas.
| | - |  | --------------------------------------------------------------------------------------------



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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.



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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.



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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.



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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:

| |  |  | relatively minor changes in the supply of, and demand for, domestic and foreign energy;
| | - |  | ---------------------------------------------------------------------------------------

| |  |  | market uncertainty;
| | - |  | -------------------

| |  |  | the availability and cost of transportation capacity;
| | - |  | -----------------------------------------------------



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| |  |  | the level of consumer product demand;
| | - |  | -------------------------------------

| |  |  | geopolitical conditions impacting supply and demand for natural gas and crude oil;
| | - |  | ----------------------------------------------------------------------------------

| |  |  | weather conditions;
| | - |  | -------------------

| |  |  | domestic and foreign governmental regulations and taxes;
| | - |  | --------------------------------------------------------

| |  |  | the price and availability of alternative fuels;
| | - |  | ------------------------------------------------

| |  |  | speculation in the commodity futures markets;
| | - |  | ---------------------------------------------

| |  |  | overall domestic and global economic conditions;
| | - |  | ------------------------------------------------

| |  |  | the price of natural gas, crude oil, NGL and liquefied natural gas imports; and
| | - |  | -------------------------------------------------------------------------------

| |  |  | the effect of worldwide energy conservation measures.
| | - |  | -----------------------------------------------------

These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services. As
commodity prices decline, 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.



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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:

| |  |  | demand for natural gas and refinery-grade crude oil;
| | - |  | ----------------------------------------------------

| |  |  | producers desire and ability to obtain necessary permits in a timely and economic manner;
| | - |  | ------------------------------------------------------------------------------------------

| |  |  | natural gas field characteristics and production performance;
| | - |  | -------------------------------------------------------------

| |  |  | surface access and infrastructure issues; and
| | - |  | ---------------------------------------------

| |  |  | capacity constraints on natural gas, crude oil and natural gas liquids pipelines from the producing areas and our facilities.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------

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

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



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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:

| |  |  | the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
| | - |  | ----------------------------------------------------------------------------------------------------

| |  |  | the federal Clean Water Act and analogous state laws that regulate discharge of wastewaters from our facilities to state and federal waters;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the federal Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws that regulate the cleanup of hazardous substances that may
have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste
from our facilities.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

There is 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



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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.



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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:

| |  |  | our general partner, which is owned by ONEOK, and the Board of Directors of our general partner are allowed to take into account the interests of parties other than
us in resolving conflicts of interest, which has the effect of limiting their fiduciary duties to our unitholders;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Partnership Agreement limits the liability and reduces the fiduciary duties of the members of the Board of Directors of our general partner and also restricts
the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the Board of Directors of our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and
issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the Board of Directors of our general partner approves the amount and timing of any capital expenditures and determines whether they are maintenance capital
expenditures or growth capital expenditures, which can affect the amount of cash that is distributed to our unitholders;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the Board of Directors of our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of
the borrowing is to make incentive distributions;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the Board of Directors of our general partner and its Audit Committee determine which costs incurred by the Board of Directors, our general partner and its
affiliates are reimbursable by us;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Partnership Agreement does not restrict the members of the Board of Directors of our general partner from causing us to pay the Board of Directors, our general
partner or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of the common units; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | the Board of Directors and Audit Committee of our general partner decide whether to retain separate counsel, accountants or others to perform services for us.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

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

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

| |  |  | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our
general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise
of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination (through its Board of Directors) whether or not to consent to any merger or consolidation of us;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in
good faith, meaning it believed the decision was in our best interests;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | provides that our general partner is entitled to make other decisions in good faith if it reasonably believes that the decision is in our best
interests;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Audit Committee and not involving a vote of unitholders
must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be fair and reasonable to us, as determined by our general partner in good faith, and that, in
determining whether a transaction or resolution is fair and reasonable, our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous
or beneficial to us; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | provides that our general partner and its affiliates, officers and directors will not be liable for monetary damages to us or our limited partners for any acts or
omissions so long as such person acted in good faith and in a manner believed to be in, or not opposed to, the best interest of us and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

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

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

Our senior unsecured 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



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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:

| |  |  | make it more difficult for us to satisfy our obligations with respect to our notes and our other indebtedness, which could in turn result in an event of default on
such other indebtedness or our notes;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | diminish our ability to withstand a downturn in our business or the economy;
| | - |  | ----------------------------------------------------------------------------

| |  |  | require us to dedicate a substantial portion of our cash flow from operations to debt service payments, reducing the availability of cash for working capital,
capital expenditures, acquisitions, distributions to partners, general corporate purposes or other purposes;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------

| |  |  | place us at a competitive disadvantage compared with our competitors that have proportionately less debt.
| | - |  | ---------------------------------------------------------------------------------------------------------

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

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

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

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



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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 unitholders proportionate ownership interest in us will decrease;
| | - |  | ----------------------------------------------------------------------

| |  |  | the distribution paid on each unit may decrease;
| | - |  | ------------------------------------------------

| |  |  | the relative voting strength of each previously outstanding unit may be diminished; and
| | - |  | ---------------------------------------------------------------------------------------

| |  |  | the market price of the common units may decline.
| | - |  | -------------------------------------------------

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

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

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

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

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

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

TAX RISKS

Our tax treatment depends on our status as a partnership for federal income tax purposes. 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.



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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.



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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



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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:

| |  |  | approximately 10,100 miles and 4,200 miles of gathering pipelines with capacity owned, leased or contracted for in the Mid-Continent and Rocky Mountain regions,
respectively,
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | nine active processing plants, with approximately 645 MMcf/d of owned processing capacity in the Mid-Continent region, and four active processing plants with
approximately 80 MMcf/d of owned, leased or contracted processing capacity in the Rocky Mountain region, and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | approximately 18 MBbl/d of natural gas liquids fractionation capacity in the Mid-Continent and Rocky Mountain regions.
| | - |  | ----------------------------------------------------------------------------------------------------------------------

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,



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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:

| |  |  | approximately 1,290 miles of FERC-regulated interstate natural gas pipelines with approximately 2.4 Bcf/d of peak transportation capacity,
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | approximately 5,630 miles of intrastate natural gas gathering and state-regulated intrastate transmission pipelines with peak transportation capacity of
approximately 2.9 Bcf/d,
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | approximately 51.6 Bcf of total active working gas storage capacity, and
| | - |  | ------------------------------------------------------------------------

| |  |  | our 50 percent interest in Northern Border Pipeline.
| | - |  | ----------------------------------------------------

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:

| |  |  | approximately 2,570 miles of owned and contracted natural gas liquids gathering pipelines with peak capacity of approximately 270 MBbl/d,
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------

| |  |  | approximately 163 miles of natural gas liquids distribution pipelines with peak transportation capacity of approximately 62 MBbl/d,
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------

| |  |  | interests in four natural gas liquids fractionators with proportional operating capacity of approximately 399 MBbl/d,
| | - |  | ---------------------------------------------------------------------------------------------------------------------

| |  |  | one 9 MBbl/d isomerization unit, and
| | - |  | ------------------------------------

| |  |  | seven owned or leased storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 24,600 MBbl.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------

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.



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

| |  |  | approximately 720 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 93 MBbl/d,
| | - |  | --------------------------------------------------------------------------------------------------------------------------------

| |  |  | approximately 3,350 miles of FERC-regulated natural gas liquids distribution pipelines with peak transportation capacity of 434 MBbl/d,
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------

| |  |  | eight NGL product terminals in Missouri, Nebraska, Iowa and Illinois, and
| | - |  | -------------------------------------------------------------------------

| |  |  | above-and below-ground storage facilities with 978 MBbl operating capacity.
| | - |  | ---------------------------------------------------------------------------

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.



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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.



|               |  |   |                             |  |   |                             |  |   |       |  |   |       |  | 
|-------------- |  | - | --------------------------- |  | - | --------------------------- |  | - | ----- |  | - | ----- |  | 
|               |  |   | Year EndedDecember 31, 2007 |  |   | Year EndedDecember 31, 2006 |  |  
|               |  |   | High                        |  |   | Low                         |  |   | High  |  |   | Low   |  | 
|First Quarter  |  | $ | 67.80                       |  | $ | 62.62                       |  | $ | 49.15 |  | $ | 42.74 |  | 
|Second Quarter |  | $ | 72.42                       |  | $ | 66.82                       |  | $ | 51.35 |  | $ | 47.63 |  | 
|Third Quarter  |  | $ | 70.70                       |  | $ | 58.20                       |  | $ | 56.25 |  | $ | 49.99 |  | 
|Fourth Quarter |  | $ | 65.41                       |  | $ | 59.00                       |  | $ | 65.91 |  | $ | 57.08 |  | 

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.



|               |  |                          |      |      |   |      |  | 
|-------------- |  | ------------------------ | ---- | ---- | - | ---- |  | 
|               |  | Years Ended December 31, |      |     
|               |  | 2007                     |      | 2006 |   |     
|First Quarter  |  | $                        | 0.98 |      | $ | 0.80 |  | 
|Second Quarter |  | $                        | 0.99 |      | $ | 0.88 |  | 
|Third Quarter  |  | $                        | 1.00 |      | $ | 0.95 |  | 
|Fourth Quarter |  | $                        | 1.01 |      | $ | 0.97 |  | 

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:

| |  |  | 15 percent of amounts distributed in excess of $0.605 per unit,
| | - |  | ---------------------------------------------------------------

| |  |  | 25 percent of amounts distributed in excess of $0.715 per unit, and
| | - |  | -------------------------------------------------------------------

| |  |  | 50 percent of amounts distributed in excess of $0.935 per unit.
| | - |  | ---------------------------------------------------------------

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.



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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.

LOGO



|                      |  |                           |        |      |   |        |  |      |        |      |   |        |  |   |        |  |   |        |  | 
|--------------------- |  | ------------------------- | ------ | ---- | - | ------ |  | ---- | ------ | ---- | - | ------ |  | - | ------ |  | - | ------ |  | 
|                      |  | Cumulative Total Return   |        |     
|                      |  | Years Ending December 31, |        |     
|                      |  | 2002                      |        | 2003 |   | 2004   |  | 2005 |        | 2006 |   | 2007   |  |  
|ONEOK Partners, L.P.  |  | $                         | 100.00 |      | $ | 112.19 |  | $    | 148.69 |      | $ | 138.50 |  | $ | 224.08 |  | $ | 230.01 |  | 
|S&P 500 Index         |  | $                         | 100.00 |      | $ | 128.68 |  | $    | 142.69 |      | $ | 149.70 |  | $ | 173.34 |  | $ | 182.87 |  | 
|Alerian MLP Index (a) |  | $                         | 100.00 |      | $ | 144.55 |  | $    | 168.65 |      | $ | 179.30 |  | $ | 225.60 |  | $ | 254.24 |  | 



|(a) - | The Alerian MLP Index measures the composite performance of the 50 most prominent energy master limited partnerships, and is calculated by Standard & Poors using a
float-adjusted, capitalization-weighted methodology.
|----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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ITEM 6. SELECTED FINANCIAL DATA

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



|                                                  |  |                                                  |           |      |   |           |  |      |           |      |   |           |  |   |           |   |  | 
|------------------------------------------------- |  | ------------------------------------------------ | --------- | ---- | - | --------- |  | ---- | --------- | ---- | - | --------- |  | - | --------- | - |  | 
|                                                  |  | Years Ended December 31,                         |           |      |  
|                                                  |  | 2007                                             |           | 2006 |   | 2005      |  | 2004 |           | 2003 |   |           | 
|                                                  |  | ( In thousands of dollars, except per unit data) |           |      |  
|Operating revenue                                 |  | $                                                | 5,831,558 |      | $ | 4,738,248 |  | $    | 703,944   |      | $ | 590,383   |  | $ | 550,948   |   |  | 
|Income (loss) from continuing operations          |  | $                                                | 407,747   |      | $ | 445,186   |  | $    | 146,507   |      | $ | 140,921   |  | $ | (97,149   | ) |  | 
|Net income (loss)                                 |  | $                                                | 407,747   |      | $ | 445,186   |  | $    | 147,013   |      | $ | 144,720   |  | $ | (88,454   | ) |  | 
|Total assets                                      |  | $                                                | 6,112,065 |      | $ | 4,921,717 |  | $    | 2,527,766 |      | $ | 2,514,690 |  | $ | 2,570,583 |   |  | 
|Long-term debt, including current maturities      |  | $                                                | 2,617,326 |      | $ | 2,031,529 |  | $    | 1,123,971 |      | $ | 1,139,358 |  | $ | 1,238,986 |   |  | 
|Per unit income (loss) from continuing operations |  | $                                                | 4.21      |      | $ | 5.01      |  | $    | 2.92      |      | $ | 2.81      |  | $ | (2.27     | ) |  | 
|Per unit net income (loss)                        |  | $                                                | 4.21      |      | $ | 5.01      |  | $    | 2.93      |      | $ | 2.89      |  | $ | (2.08     | ) |  | 
|Distributions per unit                            |  | $                                                | 3.98      |      | $ | 3.60      |  | $    | 3.20      |      | $ | 3.20      |  | $ | 3.20      |   |  | 

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



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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 66-2/3percent 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.



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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



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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



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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.



|                                                |  |                        |         |  | 
|----------------------------------------------- |  | ---------------------- | ------- |  | 
|                                                |  |                        |         |  | 
|                                                |  | (Thousands of dollars) |         | 
|Natural Gas Gathering and Processing            |  | $                      | 90,037  |  | 
|Natural Gas Pipelines                           |  |                        | 128,997 |  | 
|Natural Gas Liquids Gathering and Fractionation |  |                        | 175,566 |  | 
|Total goodwill                                  |  | $                      | 394,600 |  | 
|                                               

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.



|                                                |  |                        |         |  | 
|----------------------------------------------- |  | ---------------------- | ------- |  | 
|                                                |  |                        |         |  | 
|                                                |  | (Thousands of dollars) |         | 
|Natural Gas Liquids Gathering and Fractionation |  | $                      | 273,751 |  | 
|Natural Gas Liquids Pipelines                   |  |                        | 13,733  |  | 
|Total intangible assets                         |  | $                      | 287,484 |  | 
|                                               

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



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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.



|                                                          |  |                          |           |      |   |           |  |   |         |  | 
|--------------------------------------------------------- |  | ------------------------ | --------- | ---- | - | --------- |  | - | ------- |  | 
|                                                          |  | Years Ended December 31, |           |     
|Financial Results                                         |  | 2007                     |           | 2006 |   | 2005      |  |  
|                                                          |  | (Thousands of dollars)   |           |     
|Operating revenue                                         |  | $                        | 5,831,558 |      | $ | 4,738,248 |  | $ | 703,944 |  | 
|Cost of sales and fuel                                    |  |                          | 4,935,665 |      |   | 3,894,700 |  |   | 210,082 |  | 
|Net margin                                                |  |                          | 895,893   |      |   | 843,548   |  |   | 493,862 |  | 
|Operating costs                                           |  |                          | 337,356   |      |   | 325,774   |  |   | 151,084 |  | 
|Depreciation and amortization                             |  |                          | 113,704   |      |   | 122,045   |  |   | 86,010  |  | 
|Gain on sale of assets                                    |  |                          | 1,950     |      |   | 115,483   |  |   | -       |  | 
|Operating income                                          |  | $                        | 446,783   |      | $ | 511,212   |  | $ | 256,768 |  | 
|                                                         
|Equity earnings from investments                          |  | $                        | 89,908    |      | $ | 95,883    |  | $ | 24,736  |  | 
|Allowance for equity funds used during construction       |  | $                        | 12,538    |      | $ | 2,205     |  | $ | 527     |  | 
|Interest expense                                          |  | $                        | 138,947   |      | $ | 133,482   |  | $ | 86,903  |  | 
|Minority interests in income of consolidated subsidiaries |  | $                        | 416       |      | $ | 2,392     |  | $ | 45,674  |  | 

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



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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 66-2/3percent 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 33-1/3percent 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 66-2/3percent 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.



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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.



|                                                                          |  |                          |           |   |      |   |           |      |  |   |         |   |  | 
|------------------------------------------------------------------------- |  | ------------------------ | --------- | - | ---- | - | --------- | ---- |  | - | ------- | - |  | 
|                                                                          |  | Years Ended December 31, |           |   |     
|Financial Results                                                         |  | 2007                     |           |   | 2006 |   |           | 2005 |  |   |        
|                                                                          |  | (Thousands of dollars)   |           |   |     
|Natural gas liquids and condensate sales                                  |  | $                        | 673,800   |   |      | $ | 646,548   |      |  | $ | 123,088 |   |  | 
|Gas sales                                                                 |  |                          | 636,761   |   |      |   | 706,318   |      |  |   | 107,999 |   |  | 
|Gathering, compression, dehydration and processing fees and other revenue |  |                          | 148,089   |   |      |   | 123,224   |      |  |   | 44,200  |   |  | 
|Cost of sales and fuel                                                    |  |                          | 1,092,139 |   |      |   | 1,105,329 |      |  |   | 180,052 |   |  | 
|Net margin                                                                |  |                          | 366,511   |   |      |   | 370,761   |      |  |   | 95,235  |   |  | 
|Operating costs                                                           |  |                          | 135,422   |   |      |   | 147,487   |      |  |   | 34,476  |   |  | 
|Depreciation and amortization                                             |  |                          | 45,099    |   |      |   | 43,032    |      |  |   | 16,045  |   |  | 
|Gain on sale of assets                                                    |  |                          | 1,825     |   |      |   | 373       |      |  |   | -       |   |  | 
|Operating income                                                          |  | $                        | 187,815   |   |      | $ | 180,615   |      |  | $ | 44,714  |   |  | 
|                                                                         
|Equity earnings from investments                                          |  | $                        | 26,399    |   |      | $ | 22,616    |      |  | $ | 22,473  |   |  | 
|                                                                          |  |                         
|                                                                          |  | Years Ended December 31, |           |   |     
|Operating Information                                                     |  | 2007                     |           |   | 2006 |   |           | 2005 |  |   |        
|Natural gas gathered (BBtu/d)                                             |  |                          | 1,171     |   |      |   | 1,168     |      |  |   | 274     |   |  | 
|Natural gas processed(BBtu/d)                                             |  |                          | 621       |   |      |   | 988       |      |  |   | 94      |   |  | 
|Natural gas liquids sales (MBbl/d)                                        |  |                          | 38        |   |      |   | 42        |      |  |   | 8       |   |  | 
|Natural gas sales (BBtu/d)                                                |  |                          | 281       |   |      |   | 302       |      |  |   | 43      |   |  | 
|Capital expenditures (Thousands of dollars)                               |  | $                        | 83,820    |   |      | $ | 80,982    |      |  | $ | 16,602  |   |  | 
|Realized composite NGL sales price ($/gallon)                             |  | $                        | 1.06      |   |      | $ | 0.93      |      |  | $ | 0.92    |   |  | 
|Realized condensate sales price ($/Bbl)                                   |  | $                        | 67.35     |   |      | $ | 57.84     |      |  | $ | -       |   |  | 
|Realized natural gas sales price ($/MMBtu)                                |  | $                        | 6.21      |   |      | $ | 6.31      |      |  | $ | 6.87    |   |  | 
|Realized gross processing spread ($/MMBtu)                                |  | $                        | 5.21      |   |      | $ | 5.05      |      |  | $ | -       |   |  | 
|                                                                          |  |                         
|                                                                          |  | Years Ended December 31, |           |   |     
|                                                                          |  | 2007                     |           |   | 2006 |   |           | 2005 |  |   |        
|Percent of proceeds                                                       |  |                          |           |   |      |   |           |      |  |   |         |   |  | 
|Wellhead purchases (MMBtu/d)                                              |  |                          | 83,993    |   |      |   | 121,199   |      |  |   | -       |   |  | 
|NGL sales (Bbl/d)                                                         |  |                          | 5,959     |   |      |   | 7,364     |      |  |   | 2,376   |   |  | 
|Residue sales (MMBtu/d)                                                   |  |                          | 34,010    |   |      |   | 28,855    |      |  |   | 12,502  |   |  | 
|Condensate sales(Bbl/d)                                                   |  |                          | 719       |   |      |   | 1,103     |      |  |   | -       |   |  | 
|Percentage of total net margin                                            |  |                          | 56        | % |      |   | 55        | %    |  |   | 57      | % |  | 
|Fee-based                                                                 |  |                          |           |   |      |   |           |      |  |   |         |   |  | 
|Wellhead volumes (MMBtu/d)                                                |  |                          | 1,170,502 |   |      |   | 1,168,478 |      |  |   | 274,359 |   |  | 
|Average rate ($/MMBtu)                                                    |  | $                        | 0.25      |   |      | $ | 0.25      |      |  | $ | 0.41    |   |  | 
|Percentage of total net margin                                            |  |                          | 30        | % |      |   | 29        | %    |  |   | 43      | % |  | 
|Keep-whole                                                                |  |                          |           |   |      |   |           |      |  |   |         |   |  | 
|NGL shrink (MMBtu/d)                                                      |  |                          | 23,636    |   |      |   | 37,029    |      |  |   | -       |   |  | 
|Plant fuel (MMBtu/d)                                                      |  |                          | 2,846     |   |      |   | 4,959     |      |  |   | -       |   |  | 
|Condensate shrink (MMBtu/d)                                               |  |                          | 2,490     |   |      |   | 3,328     |      |  |   | -       |   |  | 
|Condensate sales (Bbl/d)                                                  |  |                          | 504       |   |      |   | 683       |      |  |   | -       |   |  | 
|Percentage of total net margin                                            |  |                          | 14        | % |      |   | 16        | %    |  |   | 0       | % |  | 



38



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##### Table of Contents

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

| |  |  | a decrease of $25.8 million from lower volumes processed as a result of contract terminations at the Bushton Plant in late 2006,
| | - |  | --------------------------------------------------------------------------------------------------------------------------------

| |  |  | a decrease of $5.6 million primarily due to lower processed volumes associated with winter storms and summer flooding in the Mid-Continent region and reduced
processing capacity due to a temporary shutdown to install additional processing and fractionation capacity at our Grasslands plant located in the Williston Basin, partially offset by
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $13.0 million in fee margins primarily from improved contractual terms and increased volumes in our gathering business,
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $8.6 million due to one-time favorable contract settlements that occurred in the fourth quarter of 2007, and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $5.5 million due to higher realized natural gas liquids and natural gas prices.
| | - |  | ----------------------------------------------------------------------------------------------

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:

| |  |  | an increase of $263.1 million related to the acquisition of ONEOKs natural gas gathering and processing assets,
| | - |  | ----------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $3.2 million resulting from favorable commodity pricing for natural gas and NGL products on POP contracts in the Rocky Mountain region, net of
hedging, and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $9.0 million resulting from increased natural gas volumes gathered and processed in the Rocky Mountain region, partially offset by lower average
gathering rates.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



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##### Table of Contents

Natural Gas Pipelines

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

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

| |  |  | In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. We and TC PipeLines each now own a 50 percent
interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In April 2006, we acquired the 66-2/3percent interest in Guardian Pipeline not previously owned by us for approximately $77 million, increasing our ownership interest to 100 percent.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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.



|                                                                                                                                                                                |  |                          |         |      |   |         |  |   |         |   |  | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | ------- | ---- | - | ------- |  | - | ------- | - |  | 
|                                                                                                                                                                                |  | Years Ended December 31, |         |      |  
|Financial Results                                                                                                                                                               |  | 2007                     |         | 2006 |   | 2005    |  |   |        
|                                                                                                                                                                                |  | (Thousands of dollars)   |         |      |  
|Transportation revenue                                                                                                                                                          |  | $                        | 228,173 |      | $ | 234,187 |  | $ | 395,670 |   |  | 
|Storage revenue                                                                                                                                                                 |  |                          | 54,809  |      |   | 49,486  |  |   | -       |   |  | 
|Gas sales and other revenue                                                                                                                                                     |  |                          | 18,982  |      |   | 33,335  |  |   | 8,415   |   |  | 
|Cost of sales                                                                                                                                                                   |  |                          | 60,867  |      |   | 70,211  |  |   | 30,030  |   |  | 
|Net margin                                                                                                                                                                      |  |                          | 241,097 |      |   | 246,797 |  |   | 374,055 |   |  | 
|Operating costs                                                                                                                                                                 |  |                          | 96,584  |      |   | 91,516  |  |   | 92,630  |   |  | 
|Depreciation and amortization                                                                                                                                                   |  |                          | 32,380  |      |   | 32,841  |  |   | 67,257  |   |  | 
|Gain on sale of assets                                                                                                                                                          |  |                          | 79      |      |   | 114,890 |  |   | -       |   |  | 
|Operating income                                                                                                                                                                |  | $                        | 112,212 |      | $ | 237,330 |  | $ | 214,168 |   |  | 
|                                                                                                                                                                               
|Equity earnings from investments                                                                                                                                                |  | $                        | 62,487  |      | $ | 72,835  |  | $ | 2,263   |   |  | 
|Allowance for equity funds used during construction                                                                                                                             |  | $                        | 3,670   |      | $ | 918     |  | $ | 527     |   |  | 
|Minority interest in income of consolidated subsidiaries                                                                                                                        |  | $                        | 387     |      | $ | 2,392   |  | $ | 45,674  |   |  | 
|                                                                                                                                                                                |  |                         
|                                                                                                                                                                                |  | Years Ended December 31, |         |      |  
|Operating Information (a)                                                                                                                                                       |  | 2007                     |         | 2006 |   | 2005    |  |   |        
|Natural gas transported (MMcf/d)                                                                                                                                                |  |                          | 3,579   |      |   | 3,634   |  |   | 3,808   |   |  | 
|Average natural gas price                                                                                                                                                       |  |                          |         |      |   |         |  |   |         |   |  | 
|Mid-continent region ($/MMBtu)                                                                                                                                                  |  | $                        | 6.05    |      | $ | 6.04    |  |   | (b      | ) |  | 
|Capital expenditures (Thousands of dollars)                                                                                                                                     |  | $                        | 138,919 |      | $ | 48,598  |  | $ | 39,641  |   |  | 
|(a)    Includes volumes for consolidated entities only. (b)    Companies in the Mid-Continent region were acquired as part of the ONEOK Transactions effective
January 1, 2006.

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

| |  |  | a decrease of $7.1 million from natural gas transportation margins, as a result of lower throughput and higher fuel costs,
| | - |  | --------------------------------------------------------------------------------------------------------------------------

| |  |  | a decrease of $2.8 million primarily due to the expiration of reimbursements associated with an intrastate natural gas transportation construction project in
Oklahoma, and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a decrease of $0.9 million due to a reduction in operational natural gas inventory sales, partially offset by
| | - |  | -------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $5.4 million from natural gas storage margins as a result of new and renegotiated contracts.
| | - |  | -----------------------------------------------------------------------------------------------------------

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



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##### Table of Contents

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

| |  |  | a decrease of $321.7 million related to Northern Border Pipeline, which is no longer consolidated as of January 1, 2006, offset by
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $149.7 million due to acquisition of the pipelines and storage assets from ONEOK,
| | - |  | ------------------------------------------------------------------------------------------------

| |  |  | an increase of $35.6 million due to the consolidation of Guardian Pipeline,
| | - |  | ---------------------------------------------------------------------------

| |  |  | an increase of $7.7 million from natural transportation revenues as a result of lower fuel costs and higher throughput, and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $1.7 million due to the acquisition of OkTex Pipeline from ONEOK.
| | - |  | --------------------------------------------------------------------------------

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 33-1/3percent 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 66-2/3percent 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.



|                                                                            |  |                          |           |      |   |           |  | 
|--------------------------------------------------------------------------- |  | ------------------------ | --------- | ---- | - | --------- |  | 
|                                                                            |  | Years Ended December 31,
|Financial Results                                                           |  | 2007                     |           | 2006 |   |          
|                                                                            |  | (Thousands of dollars)  
|Natural gas liquids and condensate sales                                    |  | $                        | 4,310,474 |      | $ | 3,295,462 |  | 
|Storage and fractionation revenue                                           |  |                          | 276,819   |      |   | 197,514   |  | 
|Cost of sales and fuel                                                      |  |                          | 4,381,529 |      |   | 3,325,995 |  | 
|Net margin                                                                  |  |                          | 205,764   |      |   | 166,981   |  | 
|Operating costs                                                             |  |                          | 70,693    |      |   | 57,511    |  | 
|Depreciation and amortization                                               |  |                          | 23,134    |      |   | 20,738    |  | 
|Gain on sale of assets                                                      |  |                          | 39        |      |   | 47        |  | 
|Operating income                                                            |  | $                        | 111,976   |      | $ | 88,779    |  | 
|                                                                           
|                                                                            | 
|                                                                            |  | Years Ended December 31,
|Operating Information                                                       |  | 2007                     |           | 2006 |   |          
|Natural gas liquids gathered (MBbl/d)                                       |  |                          | 228       |      |   | 206       |  | 
|Natural gas liquids sales (MBbl/d)                                          |  |                          | 231       |      |   | 207       |  | 
|Natural gas liquids fractionated (MBbl/d)                                   |  |                          | 356       |      |   | 313       |  | 
|Conway-to-Mont Belvieu OPIS average spreadEthane/Propane mixture ($/gallon) |  | $                        | 0.06      |      | $ | 0.05      |  | 
|Capital expenditures (Thousands of dollars)                                 |  | $                        | 123,555   |      | $ | 21,761    |  | 



41



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##### Table of Contents

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

| |  |  | an increase of $17.8 million due to higher exchange net margin primarily driven by increased volumes due to new supply connections, improved natural gas processing
economics and increased fractionation volumes at our Mont Belvieu fractionator,
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $13.5 million due to higher product price spreads and higher isomerization price spreads, and
| | - |  | ------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $7.6 million due to new storage contracts entered into in the second quarter of 2007 and our acquisition of the Mont Belvieu storage assets in the
fourth quarter of 2006.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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.

| |  |  | 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 approximately 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 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 Pipelines
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 Pipelines segment for the periods indicated.



|                                                         |  |                          |         |      |   |        |  | 
|-------------------------------------------------------- |  | ------------------------ | ------- | ---- | - | ------ |  | 
|                                                         |  | Years Ended December 31,
|Financial Results                                        |  | 2007                     |         | 2006 |   |       
|                                                         |  | (Thousands of dollars)  
|Transportation and gathering revenue                     |  | $                        | 90,441  |      | $ | 66,433 |  | 
|Storage revenue                                          |  |                          | 768     |      |   | -      |  | 
|Gas sales and other revenue                              |  |                          | 626     |      |   | 63     |  | 
|Cost of sales and fuel                                   |  |                          | 10,363  |      |   | 6,049  |  | 
|Net margin                                               |  |                          | 81,472  |      |   | 60,447 |  | 
|Operating costs                                          |  |                          | 28,957  |      |   | 19,333 |  | 
|Depreciation and amortization                            |  |                          | 13,062  |      |   | 12,035 |  | 
|Gain on sale of assets                                   |  |                          | 7       |      |   | 7      |  | 
|Operating income                                         |  | $                        | 39,460  |      | $ | 29,086 |  | 
|                                                        
|Equity earnings from investments                         |  | $                        | 1,022   |      | $ | 432    |  | 
|Allowance for equity funds used during construction      |  | $                        | 8,868   |      | $ | 1,287  |  | 
|Minority interest in income of consolidated subsidiaries |  | $                        | 29      |      | $ | -      |  | 
|                                                         | 
|                                                         |  | Years Ended December 31,
|Operating Information                                    |  | 2007                     |         | 2006 |   |       
|Natural gas liquids transported (MBbl/d)                 |  |                          | 299     |      |   | 200    |  | 
|Natural gas liquids gathered (MBbl/d)                    |  |                          | 81      |      |   | 60     |  | 
|Capital expenditures (Thousands of dollars)              |  | $                        | 363,460 |      | $ | 49,322 |  | 

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

| |  |  | an increase of $11.5 million due to incremental margin from our acquired assets from Kinder Morgan in October 2007 and
| | - |  | ----------------------------------------------------------------------------------------------------------------------

| |  |  | an increase of $9.5 million primarily due to increased throughput from new supply connections and increased production volume from existing supply connections to
our natural gas liquids gathering pipelines.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



42



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##### Table of Contents

Operating costs increased $9.6 million for 2007, compared with 2006, primarily due to $5.8 million in incremental
operating expenses associated with our acquired assets from Kinder Morgan, as well as higher employee-related costs.

Depreciation and amortization
increased for 2007, compared with 2006, primarily due to incremental operating expenses associated with our acquired assets from Kinder Morgan.

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

Other

In 2007, we recorded a net loss of $1.6 million to maintain the standby status of the Black Mesa facility. We
recorded a loss on Black Mesa for 2006 of $12.0 million, which included an after-tax reduction to net income of $10.6 million for the goodwill and asset impairments recognized during the year, compared with net income in 2005 of $3.9 million. We
expect that maintaining standby status of the Black Mesa facilities would result in a loss in 2008 of approximately $1.6 million if we do not divest or decommission the pipeline. We plan to either divest the Black Mesa pipeline or commence
decommissioning of the pipeline during 2008.

Contingencies

Legal Proceedings -We are a party to various litigation matters and claims that are in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome
of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

Other - As a
result of an internal review of a transaction that was brought to the attention of one of our affiliates by a third party, we have commenced an internal review of transactions that may have violated FERC capacity release rules or related rules. We
have notified the FERC of this review and expect to file a report with the FERC by mid-March 2008 concerning any violations. At this time, we do not believe that penalties, if any, associated with potential violations will have a material impact on
our results of operations, financial position or liquidity.

LIQUIDITY AND CAPITAL RESOURCES

General - Our principal sources of liquidity include cash generated from operating activities, bank credit facilities, debt issuances and the sale of limited
partner units. We fund our operating expenses, debt service and cash distributions to our limited and general partners primarily with operating cash flow.

Part of our growth strategy is to expand our existing businesses and strategically acquire related businesses that strengthen and complement our existing assets. Capital resources for acquisitions and maintenance and growth expenditures may
be funded by a variety of sources, including those listed above as our principal sources of liquidity. Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity and other recessionary
concerns. During this period, we have continued to have access to our 2007 Partnership Credit Agreement to fund our short-term liquidity needs, and we issued $600 million of long-term debt. Our ability to continue to access capital markets for
debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations
will enable us to maintain our current level of operations and our planned operations including capital expenditures for the foreseeable future. Our capital expenditures for 2007 and 2006 were financed through operating cash flows and short- and
long-term debt. Capital expenditures were $709.9 million and $201.7 million for 2007 and 2006, respectively, exclusive of acquisitions. The increase in capital expenditures for 2007, compared with 2006, is driven primarily by our capital projects,
which are discussed beginning on page 33.

Financing - Financing is provided through available cash, our amended and restated revolving credit
agreement (2007 Partnership Credit Agreement) and long-term debt. Other options to obtain financing include, but are not limited to, issuance of limited partner units, issuance of hybrid securities such as any trust preferred security or deferrable
interest subordinated debt issued by us or any business trusts and sale/leaseback of facilities.

The total amount of short-term borrowings authorized by
our general partners Board of Directors is $1.5 billion. At December 31, 2007, we had $900 million of credit available to us under the 2007 Partnership Credit Agreement, $100 million in borrowings outstanding under the 2007 Partnership
Credit Agreement and available cash of approximately $3.2 million.



43



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##### Table of Contents

The Guardian Pipeline revolving credit agreement terminated in November 2007. As of December 31, 2007, we could have issued $1.1 billion of additional
debt under the most restrictive provisions contained in our various borrowing agreements.

Our 2007 Partnership Credit Agreement contains typical covenants
as discussed in Note F of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. At December 31, 2007, we were in compliance with all covenants.

In November 2007, we entered into a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is being used, and a $12 million Standby Letter
of Credit Agreement with Royal Bank of Canada. Both agreements are used to support various permits required by the KDHE for our ongoing business in Kansas.

Debt Issuance - In September 2007, we completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under our existing shelf
registration statement filed with the SEC.

In September 2006, we completed an underwritten public offering of (i) $350 million aggregate principal
amount of 5.90 percent Senior Notes due 2012 (the 2012 Notes), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the 2016 Notes) and (iii) $600 million aggregate principal amount of 6.65 percent Senior
Notes due 2036 (the 2036 Notes and collectively with the 2012 Notes and the 2016 Notes, the Notes). We registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006.

For more information regarding the 2037 Notes and the Notes, refer to the discussion in Note G of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.

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.

Capitalization Structure - The following table sets forth our capitalization structure for the periods indicated.



|                               |  |              |   |  |              |   |  | 
|------------------------------ |  | ------------ | - |  | ------------ | - |  | 
|                               |  | December 31, |   |  | December 31, |   |  | 
|                               |  | 2007         |   |  | 2006         |   |  | 
|Long-term Debt                 |  | 54           | % |  | 48           | % |  | 
|Equity                         |  | 46           | % |  | 52           | % |  | 
|Debt (including notes payable) |  | 55           | % |  | 48           | % |  | 
|Equity                         |  | 45           | % |  | 52           | % |  | 

Credit Ratings - Our investment grade credit ratings as of
December 31, 2007, are shown in the table below.



|              |  |        |  |         |  | 
|------------- |  | ------ |  | ------- |  | 
|Rating Agency |  | Rating |  | Outlook |  | 
|Moodys       |  | Baa2   |  | Stable  |  | 
|S&P           |  | BBB    |  | Stable  |  | 

Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our
business. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, the interest rates on the 2007 Partnership Credit
Agreement borrowings would increase, resulting in an increase in our cost to borrow funds.

Our $250 million and $225 million long-term notes payable, due
2010 and 2011, respectively, contain provisions that require us to offer to repurchase the senior notes at par value if our Moodys or S&P credit rating falls below investment grade (Baa3 for Moodys or BBB- for S&P) and the
investment grade rating is not reinstated within a period of 40 days. Further, the indentures governing our senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures
governing our senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle
the trustee or the holders of 25 percent in aggregate principal amount of



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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 repurchases and repayment. We could also face difficulties
accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations. A decline in our credit rating below
investment grade may also require us to provide security to our counterparties in the form of cash, letters of credit or other negotiable instruments.

Other than the note repurchase obligations described above, we have determined that we do not have significant exposure to rating triggers in various other contracts and equipment leases. Rating triggers are defined as provisions that would
create an automatic default or acceleration of indebtedness based on a change in our credit rating. Our credit agreements contain provisions that would cause the cost to borrow funds to increase if our credit rating is negatively adjusted. An
adverse rating change is not defined as a default of our credit agreements.

Capital Expenditures - We classify expenditures that are expected to
generate additional revenue or significant operating efficiencies as growth capital expenditures. Any remaining capital expenditures are classified as maintenance capital expenditures.

The following tables set forth the growth and maintenance capital expenditures for 2007, 2006 and 2005.



|                                                |  |                       |       |      |   |       |  |   |      |  | 
|----------------------------------------------- |  | --------------------- | ----- | ---- | - | ----- |  | - | ---- |  | 
|Growth Capital Expenditures                     |  | 2007                  |       | 2006 |   | 2005  |  |  
|                                                |  | (Millions of dollars) |       |     
|Natural Gas Gathering and Processing            |  | $                     | 64.8  |      | $ | 59.4  |  | $ | 14.3 |  | 
|Natural Gas Pipelines                           |  |                       | 123.6 |      |   | 28.5  |  |   | 16.2 |  | 
|Natural Gas Liquids Gathering and Fractionation |  |                       | 102.4 |      |   | 7.0   |  |   | -    |  | 
|Natural Gas Liquids Pipelines                   |  |                       | 359.5 |      |   | 39.8  |  |   | -    |  | 
|Total growth capital expenditures               |  | $                     | 650.3 |      | $ | 134.7 |  | $ | 30.5 |  | 
|                                               



|                                                |  |                       |      |      |   |      |  |   |      |  | 
|----------------------------------------------- |  | --------------------- | ---- | ---- | - | ---- |  | - | ---- |  | 
|Maintenance Capital Expenditures                |  | 2007                  |      | 2006 |   | 2005 |  |  
|                                                |  | (Millions of dollars) |      |     
|Natural Gas Gathering and Processing            |  | $                     | 19.0 |      | $ | 21.6 |  | $ | 2.3  |  | 
|Natural Gas Pipelines                           |  |                       | 15.3 |      |   | 20.1 |  |   | 23.4 |  | 
|Natural Gas Liquids Gathering and Fractionation |  |                       | 21.2 |      |   | 14.7 |  |   | -    |  | 
|Natural Gas Liquids Pipelines                   |  |                       | 4.0  |      |   | 9.5  |  |   | -    |  | 
|Other                                           |  |                       | 0.1  |      |   | 1.1  |  |   | 3.7  |  | 
|Total maintenance capital expenditures          |  | $                     | 59.6 |      | $ | 67.0 |  | $ | 29.4 |  | 
|                                               

The majority of the capital expenditures are related to the growth projects discussed in more detail beginning on
page 33.

The following table summarizes our 2008 projected growth and maintenance capital expenditures, excluding AFUDC.



|                                                |  |                       |     |             |   |       |  |   |     |  | 
|----------------------------------------------- |  | --------------------- | --- | ----------- | - | ----- |  | - | --- |  | 
|2008 Projected Capital Expenditures             |  | Growth                |     | Maintenance |   | Total |  |  
|                                                |  | (Millions of dollars) |     |            
|Natural Gas Gathering and Processing            |  | $                     | 79  |             | $ | 26    |  | $ | 105 |  | 
|Natural Gas Pipelines                           |  |                       | 192 |             |   | 24    |  |   | 216 |  | 
|Natural Gas Liquids Gathering and Fractionation |  |                       | 99  |             |   | 29    |  |   | 128 |  | 
|Natural Gas Liquids Pipelines                   |  |                       | 484 |             |   | 12    |  |   | 496 |  | 
|Total projected capital expenditures            |  | $                     | 854 |             | $ | 91    |  | $ | 945 |  | 
|                                               

Additional information about these projects is included under Capital Projects on page 33. Financing
for these projects may include any, or a combination of, the following: cash from operations, borrowings under the 2007 Partnership Credit Agreement, and debt or equity offerings.

Cash Distributions - We distribute 100 percent of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited
partners. Our income is allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. The effect of any incremental income allocations for incentive distributions to our
general partner is calculated



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after the income allocation for the general partners partnership interest and before the income allocation to the limited partners.

The following table sets forth the distribution payments for the common and Class B unitholders and our general partner for their general partner and incentive
distribution interests for the periods indicated.



|                    |  |                          |       |      |   |       |  |   |       |  | 
|------------------- |  | ------------------------ | ----- | ---- | - | ----- |  | - | ----- |  | 
|                    |  | Years Ended December 31, |       |     
|                    |  | 2007                     |       | 2006 |   | 2005  |  |  
|                    |  | (Millions of dollars)    |       |     
|Common unitholders  |  | $                        | 184.7 |      | $ | 167.0 |  | $ | 148.5 |  | 
|Class B unitholders |  |                          | 145.2 |      |   | 70.1  |  |   | -     |  | 
|General Partner     |  |                          | 54.7  |      |   | 28.4  |  |   | 11.1  |  | 

The following summarizes our quarterly cash distribution activity for 2007:

| |  |  | In January 2007, we increased our cash distribution to $0.98 per unit for the fourth quarter of 2006. The distribution was paid on February 14, 2007, to
unitholders of record on January 31, 2007.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In April 2007, we increased our cash distribution to $0.99 per unit for the first quarter of 2007. The distribution was paid on May 14, 2007, to unitholders of
record as of April 30, 2007.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In July 2007, we increased our cash distribution to $1.00 per unit for the second quarter of 2007. The distribution was paid on August 14, 2007, to unitholders
of record on July 31, 2007.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In October 2007, we increased our cash distribution to $1.01 per unit for the third quarter of 2007. The distribution was paid on November 14, 2007, to
unitholders of record on October 31, 2007.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In January 2008, we increased our cash distribution to $1.025 per unit ($4.10 on an
annualized basis) for the fourth quarter of 2007. The distribution was paid on February 14, 2008, to unitholders of record on January 31, 2008.

Additional information about our cash distributions is included under Item 5, Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, and Item 13, Certain Relationships
and Related Transactions and Director Independence.

ENVIRONMENTAL LIABILITIES

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

CASH FLOW ANALYSIS

Operating Cash Flows - Operating cash
flows increased by $98.3 million for 2007, compared with 2006, primarily as a result of changes in the components of working capital. These changes increased operating cash flows by $180.3 million, compared with an increase of $123.7 million for
2006, primarily due to increases in accounts payable, partially offset by increases in accounts receivable. Operating cash flows also increased due to a decrease in income taxes as a result of our consolidation of the ONEOK Energy Assets, as of
January 1, 2006, which were previously owned by a taxable entity.

Operating cash flows increased by $335.8 million for 2006 compared with 2005. The
increase in operating cash flows was primarily the result of the acquisition of the ONEOK Energy Assets. Changes in components of working capital, net of the effect of the acquisition, increased operating cash flow by $123.7 million, compared with a
decrease of $2.9 million in 2005, primarily as a result of decreases in accounts receivable, decreases in inventories and increases in accrued interest.

Investing Cash Flows - Cash used in investing activities was $1.0 billion for 2007, compared with $1.3 billion for 2006. Cash used in investing activities was $68.4 million for 2005.

Investing cash flows for 2007 included the following:

| |  |  | the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan in October
2007 for approximately $300 million, before working capital adjustments, and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | increased capital expenditures of $508.1 million in 2007, compared with 2006, due to our capital projects. See page 33 for discussion of our capital projects.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------



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Investing cash flows for 2006 included the following:

| |  |  | the April 2006 purchase of the ONEOK Energy Assets, which included a cash payment of approximately $1.35 billion, before adjustments,
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the acquisition of the 66-2/3percent interest in Guardian Pipeline not previously owned by us for approximately $77 million,
| | - |  | ----------------------------------------------------------------------------------------------------------------------------

| |  |  | payment to Williams of $11.6 million for initial capital expenditures in connection with the Overland Pass Pipeline Company natural gas liquids pipeline joint
venture,
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | an equity contribution to Northern Border Pipeline of $7.2 million,
| | - |  | -------------------------------------------------------------------

| |  |  | the receipt of approximately $297 million from the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines,
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------

| |  |  | increased capital expenditures of $141.9 million in 2006, compared with 2005, primarily related to the ONEOK Energy Assets, and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------

| |  |  | the impact of the deconsolidation of Northern Border Pipeline and the consolidation of the ONEOK Energy Assets and Guardian Pipeline.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------

During 2007 and 2006, we used borrowings from our 2007 Partnership Credit Agreement and cash provided by operating activities to fund our investing activities. During
2006, we also used our Bridge Facility. These borrowings were subsequently repaid with proceeds from the public offering of senior notes completed in the third quarters of 2007 and 2006.

Financing Cash Flows - Cash provided by financing activities was $289.7 million for 2007, compared with $696.9 million for 2006. Cash used in financing activities was $189.8 million for 2005.

During the third quarter of 2007, we completed an underwritten public offering of senior notes totaling $598 million in net proceeds, before offering expenses. During
the third quarter of 2006, we completed the underwritten public offering of senior notes totaling $1.4 billion in net proceeds, before offering expenses. The use of these proceeds is discussed below.

We had net borrowings of approximately $94.0 million in 2007, compared with net payments of $200.5 million in 2006. The changes occurred for the following reasons:

| |  |  | During 2007, short-term financing was primarily used to fund our capital projects. The $598 million debt issuance, net of discounts, was used to repay borrowings
under the 2007 Partnership Credit Agreement and finance the $300 million acquisition of assets, before working capital adjustments, from a subsidiary of Kinder Morgan in October 2007.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | During the second quarter of 2006, we borrowed $1.05 billion under our Bridge Facility to finance a portion of the
acquisition of the ONEOK Energy Assets and $77 million under our revolving credit agreement to acquire the 66-2/3percent
interest in Guardian Pipeline. In the third quarter of 2006, the net proceeds from the senior notes issued in 2006 discussed above were used to repay all of the amounts outstanding under our Bridge Facility and to repay $335 million of short-term
debt.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In 2005, borrowings under Northern Border Pipelines and our revolving credit agreements were primarily used to repay
amounts borrowed under previously existing credit agreements for Northern Border Pipeline and us. Total borrowings in 2005 were $165.0 million and debt repayments were $130.2 million. We also paid $2.8 million to terminate forward-starting interest
rate swaps.

We reported cash flows retained by ONEOK of $177.5 million in 2006, which represented the cash flows generated during the first quarter of
2006 by the ONEOK Energy Assets prior to the ONEOK Transactions.

In March 2006, we borrowed $33 million under our amended and restated five-year revolving
credit agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million.

Cash distributions to our general and limited partners for 2007 were $384.6 million, compared with $265.5 million in 2006, an increase of $119.1 million, primarily due to the additional units that were issued to complete the ONEOK
Transactions. Cash distributions to our general and limited partners increased $105.9 million for 2006, compared with 2005, due to increased available cash following the ONEOK Transactions described in this section under Significant
Acquisitions and Developments. We paid cash distributions of $3.98 per unit in 2007, compared with $3.60 per unit paid in 2006 and $3.20 per unit paid in 2005.



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Distributions to minority interests for 2006 decreased $60.5 million, compared with 2005, primarily due to the
deconsolidation of Northern Border Pipeline. Distributions to minority interests for 2005 included distributions related to TC PipeLines 30 percent interest in Northern Border Pipeline prior to the sale.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following
table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2007. For further discussion of the debt and operating lease agreements, see Notes G and H, respectively, of the
Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.



|                                              |  |                        |           |      |   |         |  |      |         |      |   |         |  |            |         |  |   |         |  |   |           |  | 
|--------------------------------------------- |  | ---------------------- | --------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | ---------- | ------- |  | - | ------- |  | - | --------- |  | 
|                                              |  | Payments Due by Period
|Contractual Obligations                       |  | Total                  |           | 2008 |   | 2009    |  | 2010 |         | 2011 |   | 2012    |  | Thereafter |         | 
|                                              |  | (Thousands of dollars) |           |     
|ONEOK Partners                                |  |                        |           |      |   |         |  |      |         |      |   |         |  |            |         |  |   |         |  |   |           |  | 
|$1 billion credit agreement                   |  | $                      | 100,000   |      | $ | 100,000 |  | $    | -       |      | $ | -       |  | $          | -       |  | $ | -       |  | $ | -         |  | 
|Senior notes - 8.875%                         |  |                        | 250,000   |      |   | -       |  |      | -       |      |   | 250,000 |  |            | -       |  |   | -       |  |   | -         |  | 
|Senior notes - 7.10%                          |  |                        | 225,000   |      |   | -       |  |      | -       |      |   | -       |  |            | 225,000 |  |   | -       |  |   | -         |  | 
|Senior notes - 5.90%                          |  |                        | 350,000   |      |   | -       |  |      | -       |      |   | -       |  |            | -       |  |   | 350,000 |  |   | -         |  | 
|Senior notes - 6.15%                          |  |                        | 450,000   |      |   | -       |  |      | -       |      |   | -       |  |            | -       |  |   | -       |  |   | 450,000   |  | 
|Senior notes - 6.65%                          |  |                        | 600,000   |      |   | -       |  |      | -       |      |   | -       |  |            | -       |  |   | -       |  |   | 600,000   |  | 
|Senior notes - 6.85%                          |  |                        | 600,000   |      |   | -       |  |      | -       |      |   | -       |  |            | -       |  |   | -       |  |   | 600,000   |  | 
|Guardian Pipeline                             |  |                        |           |      |   |         |  |      |         |      |   |         |  |            |         |  |   |         |  |   |           |  | 
|Senior notes - various                        |  |                        | 133,641   |      |   | 11,930  |  |      | 11,931  |      |   | 11,931  |  |            | 11,931  |  |   | 11,062  |  |   | 74,856    |  | 
|Interest payments on debt                     |  |                        | 2,789,800 |      |   | 177,600 |  |      | 176,700 |      |   | 163,700 |  |            | 140,000 |  |   | 120,200 |  |   | 2,011,600 |  | 
|Operating leases                              |  |                        | 87,964    |      |   | 18,698  |  |      | 13,784  |      |   | 12,745  |  |            | 12,622  |  |   | 5,847   |  |   | 24,268    |  | 
|Firm transportation contracts                 |  |                        | 26,820    |      |   | 11,881  |  |      | 11,260  |      |   | 3,679   |  |            | -       |  |   | -       |  |   | -         |  | 
|Financial and physical derivatives            |  |                        | 46,856    |      |   | 46,856  |  |      | -       |      |   | -       |  |            | -       |  |   | -       |  |   | -         |  | 
|Purchase commitments, rights of way and other |  |                        | 58,366    |      |   | 52,971  |  |      | 935     |      |   | 935     |  |            | 935     |  |   | 935     |  |   | 1,655     |  | 
|Total                                         |  | $                      | 5,718,447 |      | $ | 419,936 |  | $    | 214,610 |      | $ | 442,990 |  | $          | 390,488 |  | $ | 488,044 |  | $ | 3,762,379 |  | 
|                                             

Long-term Debt - Long-term debt as reported on our Consolidated Balance
Sheets includes unamortized debt discount.

Interest Payments on Debt - Interest expense is calculated by taking long-term debt and multiplying it by
the respective coupon rates.

Operating Leases - Our operating leases include a gas processing plant, storage contracts, office space, pipeline
equipment, rights-of-way and vehicles. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides processing and related services at the Bushton Plant through 2012. In exchange for such services, we pay OBPI
for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of OBPIs obligations under equipment leases covering the Bushton Plant.

Firm Transportation Contracts - Firm transportation agreements with our Natural Gas Gathering and Processing segments joint ventures require minimum monthly payments.

Financial and Physical Derivatives - Financial and physical derivatives represent fixed-price purchase commitments based on market information at
December 31, 2007, associated with our Natural Gas Liquids Gathering and Fractionation segment.

Purchase Commitments - Purchase commitments
include purchases related to our growth capital expenditures and other right of way commitments.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Annual Report on Form 10-K are forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995. The forward-looking statements relate to our anticipated financial performance, managements plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings,
market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. The following discussion is intended to identify important factors that could
cause future outcomes to differ materially from those set forth in the forward-looking statements.



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Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible
or assumed future results of our operations and other statements contained or incorporated in this Annual Report on Form 10-K identified by words such as anticipate, estimate, expect, project,
intend, plan, believe, should, goal, forecast and other words and terms of similar meaning.

You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results,
performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection
with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

| |  |  | the effects of weather and other natural phenomena on our operations, demand for our services and energy prices;
| | - |  | ----------------------------------------------------------------------------------------------------------------

| |  |  | competition from other United States and Canadian energy suppliers and transporters as well as alternative forms of energy;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------

| |  |  | the capital intensive nature of our businesses;
| | - |  | -----------------------------------------------

| |  |  | the profitability of assets or businesses acquired by us;
| | - |  | ---------------------------------------------------------

| |  |  | risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the uncertainty of estimates, including accruals and costs of environmental remediation;
| | - |  | ----------------------------------------------------------------------------------------

| |  |  | the timing and extent of changes in energy commodity prices;
| | - |  | ------------------------------------------------------------

| |  |  | the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance,
authorized rates or recovery of gas and gas transportation costs;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers desire and
ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | changes in demand for the use of natural gas because of market conditions caused by concerns about global warming or changes in governmental policies and
regulations due to climate change initiatives;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control,
including the effect on pension expense and funding resulting from changes in stock and bond market returns;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | actions by rating agencies concerning the credit ratings of us or our general partner;
| | - |  | --------------------------------------------------------------------------------------

| |  |  | the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities
or any other local, state or federal regulatory body, including the FERC;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our ability to access capital at competitive rates or on terms acceptable to us;
| | - |  | --------------------------------------------------------------------------------

| |  |  | risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become
significant;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the impact and outcome of pending and future litigation;
| | - |  | --------------------------------------------------------

| |  |  | the ability to market pipeline capacity on favorable terms, including the affects of:
| | - |  | -------------------------------------------------------------------------------------

| |  | future demand for and prices of natural gas and NGLs;
| | - | -----------------------------------------------------

| |  | competitive conditions in the overall energy market;
| | - | ----------------------------------------------------

| |  | availability of supplies of Canadian and United States natural gas;
| | - | -------------------------------------------------------------------

| |  | availability of additional storage capacity;
| | - | --------------------------------------------

| |  | weather conditions; and
| | - | -----------------------

| |  | competitive developments by Canadian and U.S. natural gas transmission peers;
| | - | -----------------------------------------------------------------------------

| |  |  | performance of contractual obligations by our customers, service providers, contractors and shippers;
| | - |  | -----------------------------------------------------------------------------------------------------

| |  |  | the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory
clearances;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our ability to acquire all necessary rights-of-way permits and consents in a timely manner, to promptly obtain all necessary materials and supplies required for
construction, and to construct pipelines without labor or contractor problems;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the mechanical integrity of facilities operated;
| | - |  | ------------------------------------------------

| |  |  | demand for our services in the proximity of our facilities;
| | - |  | -----------------------------------------------------------

| |  |  | our ability to control operating costs;
| | - |  | ---------------------------------------



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| |  |  | acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers or shippers facilities;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------

| |  |  | economic climate and growth in the geographic areas in which we do business;
| | - |  | ----------------------------------------------------------------------------

| |  |  | the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the impact of recently issued and future accounting pronouncements and other changes in accounting policies;
| | - |  | ------------------------------------------------------------------------------------------------------------

| |  |  | the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in
the Middle East and elsewhere;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
| | - |  | ------------------------------------------------------------------------------------------------------------------

| |  |  | risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory
delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the impact of unsold pipeline capacity being greater or less than expected;
| | - |  | ---------------------------------------------------------------------------

| |  |  | the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and
FERC-regulated rates;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing, storage, fractionation and transportation
facilities;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------

| |  |  | the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
| | - |  | ---------------------------------------------------------------------------------------------

| |  |  | the impact of potential impairment charges;
| | - |  | -------------------------------------------

| |  |  | the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of
information for financial reporting;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our ability to control construction costs and completion schedules of our pipelines and other projects; and
| | - |  | -----------------------------------------------------------------------------------------------------------

| |  |  | the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
| | - |  | --------------------------------------------------------------------------------------------------------------------

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking
statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report on Form 10-K. All forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a
result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk discussed below includes
forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of
actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing
of transactions.

We are exposed to market risk due to interest rate and commodity price volatility. Market risk is the risk of loss arising from adverse
changes in market rates and prices. We may use financial instruments, including forwards, swaps, collars and futures, to manage the risks of certain identifiable or anticipated transactions and achieve a more predictable cash flow. Our risk
management function follows established policies and procedures to monitor interest rates and natural gas and natural gas liquids marketing activities to ensure our hedging activities mitigate market risks. We do not use financial instruments for
trading purposes.

In accordance with Statement 133, Accounting for Derivative Instruments and Hedging Activities, as amended, we record
derivative instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of derivative instruments using available market information and appropriate valuation techniques. Changes in derivative
instruments fair value are recognized in earnings unless the instrument qualifies as a hedge under Statement 133 and meets specific hedge accounting criteria. Qualifying derivative instruments gains and losses may offset the hedged
items related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income (loss) for a cash flow hedge.



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INTEREST RATE RISK

General - We are subject to the risk of interest rate fluctuation in the normal course of business. We manage interest rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate
swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.

We terminated two floating-rate swaps in 2007. The total value we received for the terminated swaps was not material. At December 31, 2007, the interest rate on all
of our long-term debt was fixed.

Fair Value Hedges - See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K for discussion of the impact of interest-rate swaps and net interest expense savings from terminated swaps.

Total swap savings for 2007 were $2.5
million, compared with the savings of $2.0 million in 2006. Total swap savings from terminated swaps for 2008 are expected to be $3.7 million.

COMMODITY PRICE RISK

Our Natural Gas Gathering and Processing segment is exposed to commodity price risk, primarily NGLs, as a result of
receiving commodities in exchange for our services. To a lesser extent, exposures arise from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to our keep-whole processing contracts and the
risk of price fluctuations and the cost of intervening transportation at various market locations. We use commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize
earnings volatility related to natural gas, NGL and condensate price fluctuations.

We reduce our gross processing spread exposure through a combination of
physical and financial hedges. We utilize a portion of our POP equity natural gas as an offset, or natural hedge, to an equivalent portion of our keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to
NGL commodity price risk and we then use financial instruments to hedge the sale of NGLs.

The following table sets forth our Natural Gas Gathering and
Processing segments hedging information for the year ending December 31, 2008.



|                                     |  |                               |  |                        |  |               |  |    |   |  | 
|------------------------------------ |  | ----------------------------- |  | ---------------------- |  | ------------- |  | -- | - |  | 
|                                     |  | Year Ending December 31, 2008 |  |                        | 
|                                     |  | VolumesHedged                 |  | Average Price Per Unit |  | VolumesHedged |  |    |  
|Natural gas liquids (Bbl/d)(a)       |  | 8,085                         |  | $    1.28              |  | ($/gallon)    |  | 70 | % |  | 
|Condensate (Bbl/d)(a)                |  | 818                           |  | $    2.15              |  | ($/gallon)    |  | 74 | % |  | 
|Total liquid sales (Bbl/d)           |  | 8,903                         |  | $    1.36              |  | ($/gallon)    |  | 71 | % |  | 
|(a) - Hedged with fixed-price swaps. |  |                               |  |                        |  |               |  |    |   |  | 

Our commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at
December 31, 2007, excluding the effects of hedging and assuming normal operating conditions. Our condensate sales are based on the price of crude oil. We estimate the following:

| |  |  | a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $1.7 million,
| | - |  | --------------------------------------------------------------------------------------------------------------------------

| |  |  | a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.5 million, and
| | - |  | -------------------------------------------------------------------------------------------------------------------------

| |  |  | a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.3 million.
| | - |  | ----------------------------------------------------------------------------------------------------------------------

The above estimates of commodity price risk do not include any effects on demand for our services that might be caused by, or arise in conjunction with, price changes.
For example, a change in the gross processing spread may cause ethane to be sold in the natural gas stream, impacting gathering and processing margins, NGL exchange margins, natural gas deliveries and NGL volumes shipped.



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Our Natural Gas Liquids Gathering and Fractionation segment is exposed to commodity price risk primarily as a result of
NGLs in storage, spread risk associated with the relative values of the various NGL products and the relative value of NGL purchases at one location and sales at another location, known as basis risk. We have not entered into any hedges with respect
to our NGL marketing activities.

Our Natural Gas Pipelines segment is exposed to commodity price risk because our intrastate and interstate natural gas
pipelines collect natural gas from their customers for operations as part of their fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by their customers, our pipelines
must buy or sell natural gas, or store or use natural gas from inventory, which exposes us to commodity price risk. At December 31, 2007, there were no hedges in place with respect to natural gas price risk from our intrastate and interstate
pipeline operations.

See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our hedging
activities.



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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of ONEOK Partners GP, L.L.C. as General
Partner of ONEOK Partners, L.P. and to the Unitholders:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement
of income, partners equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of ONEOK Partners, L.P. and its subsidiaries (the Partnership) at December 31, 2007, and the results of
their operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Partnerships management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included
in Managements Report on Internal Control over Financial Reporting appearing under Item 9A in the Partnerships Form 10-K for the year ended December 31, 2007. Our responsibility is to express opinions on these financial
statements and on the Partnerships internal control over financial reporting based on our integrated audit. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all
material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.

A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial
reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could
have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

February 27, 2008

Tulsa, Oklahoma



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of ONEOK Partners GP, L.L.C. as General Partner of ONEOK Partners, L.P. and to the Unitholders:

We have audited the accompanying consolidated balance sheet of ONEOK Partners, L.P. and subsidiaries (the Partnership) (formerly Northern Border Partners, L.P.) as of
December 31, 2006, and the related consolidated statements of income, cash flows, and changes in partners equity and comprehensive income for each of the years in the two-year period ended December 31, 2006. These consolidated
financial statements are the responsibility of the Partnerships management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ONEOK
Partners, L.P. and subsidiaries as of December 31, 2006, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting
principles.

/s/ KPMG LLP

Tulsa Oklahoma

February 28, 2007, except for Note J, as to which the date is
February 27, 2008



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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME



|                                                          |  |                                                 |           |      |   |           |  |   |         |  | 
|--------------------------------------------------------- |  | ----------------------------------------------- | --------- | ---- | - | --------- |  | - | ------- |  | 
|                                                          |  | Years Ended December 31,                       
|                                                          |  | 2007                                            |           | 2006 |   | 2005      |  |  
|                                                          |  | (Thousands of dollars, except per unit amounts) |           |     
|Revenues                                                  |  |                                                 |           |      |   |           |  |   |         |  | 
|Operating revenue                                         |  | $                                               | 5,831,558 |      | $ | 4,738,248 |  | $ | 703,944 |  | 
|Cost of sales and fuel                                    |  |                                                 | 4,935,665 |      |   | 3,894,700 |  |   | 210,082 |  | 
|Net Margin                                                |  |                                                 | 895,893   |      |   | 843,548   |  |   | 493,862 |  | 
|Operating Expenses                                        |  |                                                 |           |      |   |           |  |   |         |  | 
|Operations and maintenance                                |  |                                                 | 302,544   |      |   | 294,207   |  |   | 112,509 |  | 
|Depreciation and amortization                             |  |                                                 | 113,704   |      |   | 122,045   |  |   | 86,010  |  | 
|General taxes                                             |  |                                                 | 34,812    |      |   | 31,567    |  |   | 38,575  |  | 
|Total Operating Expenses                                  |  |                                                 | 451,060   |      |   | 447,819   |  |   | 237,094 |  | 
|Gain on Sale of Assets                                    |  |                                                 | 1,950     |      |   | 115,483   |  |   | -       |  | 
|Operating Income                                          |  |                                                 | 446,783   |      |   | 511,212   |  |   | 256,768 |  | 
|Equity earnings from investments (Note K)                 |  |                                                 | 89,908    |      |   | 95,883    |  |   | 24,736  |  | 
|Allowance for equity funds used during construction       |  |                                                 | 12,538    |      |   | 2,205     |  |   | 527     |  | 
|Other income                                              |  |                                                 | 7,502     |      |   | 6,510     |  |   | 3,552   |  | 
|Other expense                                             |  |                                                 | 779       |      |   | 7,081     |  |   | 707     |  | 
|Interest expense                                          |  |                                                 | 138,947   |      |   | 133,482   |  |   | 86,903  |  | 
|Income before Minority Interests and Income Taxes         |  |                                                 | 417,005   |      |   | 475,247   |  |   | 197,973 |  | 
|Minority interests in income of consolidated subsidiaries |  |                                                 | 416       |      |   | 2,392     |  |   | 45,674  |  | 
|Income before income taxes                                |  |                                                 | 416,589   |      |   | 472,855   |  |   | 152,299 |  | 
|Income taxes                                              |  |                                                 | 8,842     |      |   | 27,669    |  |   | 5,792   |  | 
|Income from Continuing Operations                         |  |                                                 | 407,747   |      |   | 445,186   |  |   | 146,507 |  | 
|Discontinued operations, net of tax                       |  |                                                 | -         |      |   | -         |  |   | 506     |  | 
|Net Income                                                |  | $                                               | 407,747   |      | $ | 445,186   |  | $ | 147,013 |  | 
|                                                         
|Limited partners interest in net income:                 |  |                                                 |           |      |   |           |  |   |         |  | 
|Net income                                                |  | $                                               | 407,747   |      | $ | 445,186   |  | $ | 147,013 |  | 
|General partners interest in net income                  |  |                                                 | 58,781    |      |   | 75,654    |  |   | 10,900  |  | 
|Limited Partners Interest in Net Income                  |  | $                                               | 348,966   |      | $ | 369,532   |  | $ | 136,113 |  | 
|                                                         
|Limited partners per unit net income:                    |  |                                                 |           |      |   |           |  |   |         |  | 
|Income from continuing operations                         |  | $                                               | 4.21      |      | $ | 5.01      |  | $ | 2.92    |  | 
|Discontinued operations, net of tax                       |  |                                                 | -         |      |   | -         |  |   | 0.01    |  | 
|Net income per unit (Note L)                              |  | $                                               | 4.21      |      | $ | 5.01      |  | $ | 2.93    |  | 
|                                                         
|Number of Units Used in Computation (Thousands)           |  |                                                 | 82,891    |      |   | 73,768    |  |   | 46,397  |  | 
|                                                         

See accompanying Notes to Consolidated Financial Statements.



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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED BALANCE SHEETS



|                                                                                     |  |                        |           |   |                  |   |           |   |  | 
|------------------------------------------------------------------------------------ |  | ---------------------- | --------- | - | ---------------- | - | --------- | - |  | 
|                                                                                     |  | December 31,2007       |           |   | December 31,2006 |   |           |  
|Assets                                                                               |  | (Thousands of dollars) |           |   |                 
|Current Assets                                                                       |  |                        |           |   |                  |   |           |   |  | 
|Cash and cash equivalents                                                            |  | $                      | 3,213     |   |                  | $ | 21,102    |   |  | 
|Accounts receivable, net                                                             |  |                        | 577,989   |   |                  |   | 298,602   |   |  | 
|Affiliate receivables                                                                |  |                        | 52,479    |   |                  |   | 88,572    |   |  | 
|Gas and natural gas liquids in storage                                               |  |                        | 251,219   |   |                  |   | 198,141   |   |  | 
|Commodity exchanges and imbalances                                                   |  |                        | 82,037    |   |                  |   | 53,433    |   |  | 
|Other                                                                                |  |                        | 19,961    |   |                  |   | 33,388    |   |  | 
|Total Current Assets                                                                 |  |                        | 986,898   |   |                  |   | 693,238   |   |  | 
|                                                                                    
|Property, Plant and Equipment                                                        |  |                        |           |   |                  |   |           |   |  | 
|Property, plant and equipment                                                        |  |                        | 4,436,371 |   |                  |   | 3,424,452 |   |  | 
|Accumulated depreciation and amortization                                            |  |                        | 776,185   |   |                  |   | 660,804   |   |  | 
|Net Property, Plant and Equipment (Note A)                                           |  |                        | 3,660,186 |   |                  |   | 2,763,648 |   |  | 
|Investments and Other Assets                                                         |  |                        |           |   |                  |   |           |   |  | 
|Investments in unconsolidated affiliates (Note K)                                    |  |                        | 756,260   |   |                  |   | 748,879   |   |  | 
|Goodwill and intangible assets (Note D)                                              |  |                        | 682,084   |   |                  |   | 689,751   |   |  | 
|Other                                                                                |  |                        | 26,637    |   |                  |   | 26,201    |   |  | 
|Total Investments and Other Assets                                                   |  |                        | 1,464,981 |   |                  |   | 1,464,831 |   |  | 
|Total Assets                                                                         |  | $                      | 6,112,065 |   |                  | $ | 4,921,717 |   |  | 
|                                                                                    
|                                                                                     |  |                       
|Liabilities and Partners Equity                                                     |  |                        |           |   |                 
|Current Liabilities                                                                  |  |                        |           |   |                  |   |           |   |  | 
|Current maturities of long-term debt                                                 |  | $                      | 11,930    |   |                  | $ | 11,931    |   |  | 
|Notes payable                                                                        |  |                        | 100,000   |   |                  |   | 6,000     |   |  | 
|Accounts payable                                                                     |  |                        | 742,903   |   |                  |   | 361,967   |   |  | 
|Affiliate payables                                                                   |  |                        | 18,298    |   |                  |   | 25,737    |   |  | 
|Commodity exchanges and imbalances                                                   |  |                        | 252,095   |   |                  |   | 175,927   |   |  | 
|Other                                                                                |  |                        | 136,664   |   |                  |   | 89,471    |   |  | 
|Total Current Liabilities                                                            |  |                        | 1,261,890 |   |                  |   | 671,033   |   |  | 
|Long-term Debt, net of current
maturities                                            |  |                        | 2,605,396 |   |                  |   | 2,019,598 |   |  | 
|Deferred Credits and Other
Liabilities                                               |  |                        | 43,799    |   |                  |   | 36,818    |   |  | 
|Commitments and Contingencies                                                        |  |                        |           |   |                  |   |           |   |  | 
|Minority Interests in Consolidated
Subsidiaries                                      |  |                        | 5,802     |   |                  |   | 5,606     |   |  | 
|Partners
Equity                                                                     |  |                        |           |   |                  |   |           |   |  | 
|General partner                                                                      |  |                        | 58,415    |   |                  |   | 54,373    |   |  | 
|Common units: 46,397,214 units issued and outstanding at December 31, 2007 and 2006  |  |                        | 814,266   |   |                  |   | 803,599   |   |  | 
|Class B units: 36,494,126 units issued and outstanding at December 31, 2007 and 2006 |  |                        | 1,340,638 |   |                  |   | 1,332,276 |   |  | 
|Accumulated other comprehensive loss                                                 |  |                        | (18,141   | ) |                  |   | (1,586    | ) |  | 
|Total Partners Equity                                                               |  |                        | 2,195,178 |   |                  |   | 2,188,662 |   |  | 
|Total Liabilities and Partners Equity                                               |  | $                      | 6,112,065 |   |                  | $ | 4,921,717 |   |  | 
|                                                                                    

See accompanying Notes to Consolidated Financial Statements.



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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                                                             |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|-------------------------------------------------------------------------------------------- |  | ------------------------ | ---------- | - | ---- | - | ---------- | ---- |  | - | -------- | - |  | 
|                                                                                             |  | Years Ended December 31, |            |   |     
|                                                                                             |  | 2007                     |            |   | 2006 |   |            | 2005 |  |   |         
|Operating Activities                                                                         |  | (Thousands of dollars)   |            |   |     
|Net income                                                                                   |  | $                        | 407,747    |   |      | $ | 445,186    |      |  | $ | 147,013  |   |  | 
|Depreciation and amortization                                                                |  |                          | 113,704    |   |      |   | 122,045    |      |  |   | 86,361   |   |  | 
|Allowance for equity funds used during construction                                          |  |                          | (12,538    | ) |      |   | (2,205     | )    |  |   | (527     | ) |  | 
|Minority interests in income of consolidated subsidiaries                                    |  |                          | 416        |   |      |   | 2,392      |      |  |   | 45,674   |   |  | 
|Equity earnings from investments                                                             |  |                          | (89,908    | ) |      |   | (95,883    | )    |  |   | (24,736  | ) |  | 
|Distributions received from unconsolidated affiliates                                        |  |                          | 103,785    |   |      |   | 123,427    |      |  |   | 16,440   |   |  | 
|Gain on sale of assets                                                                       |  |                          | (1,950     | ) |      |   | (115,483   | )    |  |   | -        |   |  | 
|Changes in assets and liabilities (net of acquisition and disposition effects):              |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|Accounts receivable                                                                          |  |                          | (232,870   | ) |      |   | 42,148     |      |  |   | (12,840  | ) |  | 
|Inventories                                                                                  |  |                          | (50,042    | ) |      |   | 19,093     |      |  |   | (2,583   | ) |  | 
|Accounts payable and other current liabilities                                               |  |                          | 361,013    |   |      |   | 7,697      |      |  |   | 16,260   |   |  | 
|Commodity exchanges and imbalances, net                                                      |  |                          | 41,997     |   |      |   | 20,129     |      |  |   | -        |   |  | 
|Accrued taxes other than income                                                              |  |                          | 3,099      |   |      |   | (6,358     | )    |  |   | 518      |   |  | 
|Accrued interest                                                                             |  |                          | 9,069      |   |      |   | 23,445     |      |  |   | 915      |   |  | 
|Derivative financial instruments                                                             |  |                          | 3,028      |   |      |   | (5,220     | )    |  |   | (106     | ) |  | 
|Other assets and liabilities                                                                 |  |                          | 44,984     |   |      |   | 22,805     |      |  |   | (5,017   | ) |  | 
|Cash Provided by Operating Activities                                                        |  |                          | 701,534    |   |      |   | 603,218    |      |  |   | 267,372  |   |  | 
|Investing Activities                                                                         |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|Investments in unconsolidated affiliates                                                     |  |                          | (3,668     | ) |      |   | (6,608     | )    |  |   | (8,537   | ) |  | 
|Acquisitions                                                                                 |  |                          | (299,560   | ) |      |   | (1,396,893 | )    |  |   | -        |   |  | 
|Proceeds from sale of assets                                                                 |  |                          | 3,980      |   |      |   | 297,674    |      |  |   | -        |   |  | 
|Capital expenditures (less allowance for equity funds used during construction)              |  |                          | (709,858   | ) |      |   | (201,746   | )    |  |   | (59,882  | ) |  | 
|Increase in cash and cash equivalents attributable to previously unconsolidated subsidiaries |  |                          | -          |   |      |   | 7,496      |      |  |   | -        |   |  | 
|Decrease in cash and cash equivalents attributable to previously
consolidatedsubsidiaries    |  |                          | -          |   |      |   | (22,039    | )    |  |   | -        |   |  | 
|Cash Used in Investing Activities                                                            |  |                          | (1,009,106 | ) |      |   | (1,322,116 | )    |  |   | (68,419  | ) |  | 
|Financing Activities                                                                         |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|Cash distributions:                                                                          |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|General and limited partners                                                                 |  |                          | (384,646   | ) |      |   | (265,479   | )    |  |   | (159,624 | ) |  | 
|Minority interests                                                                           |  |                          | (220       | ) |      |   | (343       | )    |  |   | (60,870  | ) |  | 
|Cash flow retained by ONEOK (Note B)                                                         |  |                          | -          |   |      |   | (177,486   | )    |  |   | -        |   |  | 
|Borrowing (repayment) of notes payable, net                                                  |  |                          | 94,000     |   |      |   | (200,500   | )    |  |   | 40,000   |   |  | 
|Issuance of long-term debt, net of discounts                                                 |  |                          | 598,146    |   |      |   | 1,397,327  |      |  |   | -        |   |  | 
|Long-term debt financing costs                                                               |  |                          | (5,805     | ) |      |   | (12,003    | )    |  |   | (1,382   | ) |  | 
|Payment of long-term debt                                                                    |  |                          | (11,931    | ) |      |   | (40,978    | )    |  |   | (5,182   | ) |  | 
|Other financing activities                                                                   |  |                          | 139        |   |      |   | (3,628     | )    |  |   | (2,785   | ) |  | 
|Cash Provided by (Used in) Financing Activities                                              |  |                          | 289,683    |   |      |   | 696,910    |      |  |   | (189,843 | ) |  | 
|Change in Cash and Cash Equivalents                                                          |  |                          | (17,889    | ) |      |   | (21,988    | )    |  |   | 9,110    |   |  | 
|Cash and Cash Equivalents at Beginning of Period                                             |  |                          | 21,102     |   |      |   | 43,090     |      |  |   | 33,980   |   |  | 
|Cash and Cash Equivalents at End of Period                                                   |  | $                        | 3,213      |   |      | $ | 21,102     |      |  | $ | 43,090   |   |  | 
|                                                                                            
|Supplemental Cash Flow Information:                                                          |  |                          |            |   |      |   |            |      |  |   |          |   |  | 
|Cash Paid for Interest                                                                       |  | $                        | 138,606    |   |      | $ | 86,290     |      |  | $ | 91,168   |   |  | 
|                                                                                            

See accompanying Notes to Consolidated Financial Statements.



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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS EQUITY AND COMPREHENSIVE INCOME











|                                                                |  |             |  |                        |  |                 |         |   |              |   |          |   |  | 
|--------------------------------------------------------------- |  | ----------- |  | ---------------------- |  | --------------- | ------- | - | ------------ | - | -------- | - |  | 
|                                                                |  | CommonUnits |  | Class BUnits           |  | General Partner |         |   | Common Units |   |          |  
|                                                                |  | (Units)     |  | (Thousands of dollars) |  |                 |        
|Partners equity at December 31, 2004                           |  | 46,397,214  |  | -                      |  | $               | 17,593  |   |              | $ | 762,560  |   |  | 
|Net income                                                      |  | -           |  | -                      |  |                 | 10,900  |   |              |   | 136,113  |   |  | 
|Other comprehensive loss                                        |  | -           |  | -                      |  |                 | -       |   |              |   | -        |   |  | 
|Total comprehensive income                                      |  |             |  |                        |  |                 |         |   |              |   |          |   |  | 
|Distributions paid                                              |  | -           |  | -                      |  |                 | (11,152 | ) |              |   | (148,472 | ) |  | 
|Partners equity at December 31, 2005                           |  | 46,397,214  |  | -                      |  |                 | 17,341  |   |              |   | 750,201  |   |  | 
|Net income                                                      |  | -           |  | -                      |  |                 | 75,654  |   |              |   | 220,428  |   |  | 
|Other comprehensive income                                      |  | -           |  | -                      |  |                 | -       |   |              |   | -        |   |  | 
|Total comprehensive income                                      |  |             |  |                        |  |                 |         |   |              |   |          |   |  | 
|Net Income retained by ONEOK (Note B)                           |  | -           |  | -                      |  |                 | (35,818 | ) |              |   | -        |   |  | 
|Issuance of Class B units and contribution from general partner |  | -           |  | 36,494,126             |  |                 | 25,576  |   |              |   | -        |   |  | 
|Distributions paid                                              |  | -           |  | -                      |  |                 | (28,380 | ) |              |   | (167,030 | ) |  | 
|Partners equity at December 31, 2006                           |  | 46,397,214  |  | 36,494,126             |  |                 | 54,373  |   |              |   | 803,599  |   |  | 
|Net income                                                      |  | -           |  | -                      |  |                 | 58,781  |   |              |   | 195,329  |   |  | 
|Other comprehensive loss                                        |  | -           |  | -                      |  |                 | -       |   |              |   | -        |   |  | 
|Total comprehensive income                                      |  |             |  |                        |  |                 |         |   |              |   |          |   |  | 
|Other                                                           |  | -           |  | -                      |  |                 | (1      | ) |              |   | -        |   |  | 
|Distributions paid                                              |  | -           |  | -                      |  |                 | (54,738 | ) |              |   | (184,662 | ) |  | 
|Partners equity at December 31, 2007                           |  | 46,397,214  |  | 36,494,126             |  | $               | 58,415  |   |              | $ | 814,266  |   |  | 
|                                                               

See accompanying Notes to Consolidated Financial Statements.



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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS EQUITY AND COMPREHENSIVE INCOME

(Continued)



|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|--------------------------------------------------------------- |  | ---------------------- | --------- | - | ------------------------------------------ | - | ------- | --------------------- |  | - | --------- | - |  | 
|                                                                |  | Class B Units          |           |   | AccumulatedOtherComprehensiveIncome (Loss) |   |         | Total PartnersEquity |  |   |          
|                                                                |  | (Thousands of dollars) |           |   |                                           
|Partners equity at December 31, 2004                           |  | $                      | -         |   |                                            | $ | 9,181   |                       |  | $ | 789,334   |   |  | 
|Net income                                                      |  |                        | -         |   |                                            |   | -       |                       |  |   | 147,013   |   |  | 
|Other comprehensive loss                                        |  |                        | -         |   |                                            |   | (11,134 | )                     |  |   | (11,134   | ) |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Total comprehensive income                                      |  |                        |           |   |                                            |   |         |                       |  |   | 135,879   |   |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Distributions paid                                              |  |                        | -         |   |                                            |   | -       |                       |  |   | (159,624  | ) |  | 
|Partners equity at December 31, 2005                           |  |                        | -         |   |                                            |   | (1,953  | )                     |  |   | 765,589   |   |  | 
|Net income                                                      |  |                        | 149,104   |   |                                            |   | -       |                       |  |   | 445,186   |   |  | 
|Other comprehensive income                                      |  |                        | -         |   |                                            |   | 367     |                       |  |   | 367       |   |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Total comprehensive income                                      |  |                        |           |   |                                            |   |         |                       |  |   | 445,553   |   |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Net Income retained by ONEOK (Note B)                           |  |                        | -         |   |                                            |   | -       |                       |  |   | (35,818   | ) |  | 
|Issuance of Class B units and contribution from general partner |  |                        | 1,253,241 |   |                                            |   | -       |                       |  |   | 1,278,817 |   |  | 
|Distributions paid                                              |  |                        | (70,069   | ) |                                            |   | -       |                       |  |   | (265,479  | ) |  | 
|Partners equity at December 31, 2006                           |  |                        | 1,332,276 |   |                                            |   | (1,586  | )                     |  |   | 2,188,662 |   |  | 
|Net income                                                      |  |                        | 153,637   |   |                                            |   | -       |                       |  |   | 407,747   |   |  | 
|Other comprehensive loss                                        |  |                        | -         |   |                                            |   | (16,555 | )                     |  |   | (16,555   | ) |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Total comprehensive income                                      |  |                        |           |   |                                            |   |         |                       |  |   | 391,192   |   |  | 
|                                                                |  |                        |           |   |                                            |   |         |                       |  |   |           |   |  | 
|Other                                                           |  |                        | (29       | ) |                                            |   | -       |                       |  |   | (30       | ) |  | 
|Distributions paid                                              |  |                        | (145,246  | ) |                                            |   | -       |                       |  |   | (384,646  | ) |  | 
|Partners equity at December 31, 2007                           |  | $                      | 1,340,638 |   |                                            | $ | (18,141 | )                     |  | $ | 2,195,178 |   |  | 
|                                                               



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ONEOK PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



|A. | SUMMARY OF ACCOUNTING POLICIES
|-- | ------------------------------

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

Critical Accounting Policies

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

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

We assess our goodwill and intangible assets for
impairment at least annually based on Statement 142, Goodwill and Other Intangible Assets. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the
book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the
goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair
value of the goodwill, we will record an impairment charge. See Note D for more discussion of goodwill.

Intangible assets with a finite useful life are
amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing.

For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and under Statement 142, is not subject to
amortization but rather to impairment testing pursuant to APB 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.

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



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derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in
earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in a given period.

To minimize the risk of
fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collars or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, condensate, and fuel requirements. Interest rate swaps
are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash 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 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 for additional discussion of contingencies.

Significant Accounting Policies

Consolidation - Our consolidated financial statements include the assets, liabilities and results of operations for our majority-owned subsidiaries. All significant intercompany balances and transactions have
been eliminated in consolidation. We account for our investments that we do not control by the equity method of accounting. Under this method, an investment is carried at its acquisition cost, plus the equity in undistributed earnings or losses
since acquisition. Minority interest for 2006 primarily represents the 66-2/3percent interest in Guardian Pipeline that we did
not own until we acquired these interests in April 2006. Minority interest for 2005 represents the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipelines results were consolidated.

Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to
make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the
consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items which may be estimated include, but are not limited to, the economic useful life of
assets, fair value of assets and liabilities, provisions for uncollectible accounts receivable, unbilled revenues and cost of goods sold, expenses for services received but for which no invoice has been received, the results of litigation and
various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and
other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates
are recorded in the period when the facts that give rise to the revision become known.

Regulation - Our intrastate natural gas transmission
pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC and RRC. Our interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC. Accordingly, portions of our Natural Gas Pipelines
segment and Natural Gas Liquids Pipelines segment follow the accounting and reporting guidance contained in Statement 71, Accounting for the Effects of Certain Types of Regulation. During the rate-making process, regulatory authorities
may allow us to defer recognition of certain costs and permit recovery of the amounts through rates over time as opposed to expensing such costs as incurred. This allows us to stabilize rates over time rather than passing such costs on to the
customer for immediate recovery. Actions by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is



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recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations are no longer subject to the provisions
of Statement 71, a write-off of regulatory assets and costs not recovered may be required.

At December 31, 2007 and 2006, we recorded regulatory
assets of approximately $6.8 million and $9.2 million, respectively, which are currently being recovered or are expected to be recovered from our customers. Regulatory assets are being recovered as a result of approved rate proceedings over varying
time periods up to 40 years. These assets are reflected in other assets on our Consolidated Balance Sheets.

Asset Retirement Obligations -
Statement 143, Accounting for Asset Retirement Obligations, applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
Statement 143 requires that we recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the
carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an
amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and amortization expense is immaterial to our consolidated financial statements.

In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation
expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs are non-legal obligations as defined by Statement 143. However, these non-legal asset removal obligations are accounted for as a regulatory
liability under Statement 71. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to track this amount; rather these costs are addressed prospectively as depreciation rates and are set
in each general rate order. We have made an estimate of our removal cost liability using current rates since the last general rate order in each of our jurisdictions. However, significant uncertainty exists regarding the ultimate determination of
this liability pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory authorities and the liability may be adjusted as more information is obtained.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three
months or less.

Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. Our Natural Gas
Gathering and Processing segment records operating revenue when gas is processed in or transported through company facilities. Our Natural Gas Liquids Gathering and Fractionation segment records operating revenues based upon contracted services and
actual volumes exchanged or stored under service agreements in the period services are provided. Operating revenue for our Natural Gas Pipelines segment and Natural Gas Liquids Pipelines segment is recognized based upon contracted capacity and
contracted volumes transported and stored under service agreements in the period services are provided.

Property - The following table sets forth
our property, by segment, for the periods presented.



|                                                |  |                        |           |              |   |           |  | 
|----------------------------------------------- |  | ---------------------- | --------- | ------------ | - | --------- |  | 
|                                                |  | December 31,           |           | December 31, |   |          
|                                                |  | 2007                   |           | 2006         |   |          
|                                                |  | (Thousands of dollars) |           |             
|Non-Regulated                                   |  |                        |           |              |   |           |  | 
|Natural Gas Gathering and Processing            |  | $                      | 1,227,475 |              | $ | 1,133,614 |  | 
|Natural Gas Pipelines                           |  |                        | 162,390   |              |   | 162,636   |  | 
|Natural Gas Liquids Gathering and Fractionation |  |                        | 672,047   |              |   | 547,495   |  | 
|Other                                           |  |                        | 50,482    |              |   | 50,784    |  | 
|Regulated                                       |  |                        |           |              |   |           |  | 
|Natural Gas Pipelines                           |  |                        | 1,184,112 |              |   | 1,040,125 |  | 
|Natural Gas Liquids Pipelines                   |  |                        | 1,139,865 |              |   | 489,798   |  | 
|Property, plant and equipment                   |  |                        | 4,436,371 |              |   | 3,424,452 |  | 
|Accumulated depreciation and amortization       |  |                        | 776,185   |              |   | 660,804   |  | 
|Net property, plant and equipment               |  | $                      | 3,660,186 |              | $ | 2,763,648 |  | 
|                                               

Gas processing plants, natural gas liquids fractionation plants and all other properties are stated at cost. Gas
processing plants, natural gas liquids fractionation plants and all other property and equipment are depreciated using the straight-line method over the estimated useful life.



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Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.

At December 31, 2007 and 2006, property, plant and equipment on our Consolidated Balance Sheets included construction work in progress of $859.8
million and $100.5 million, respectively, that had not yet been put in service and therefore was not being depreciated.

Certain maintenance and repairs
are charged directly to expense. Gains and losses from sales or transfers of an entire operating unit or system are recognized in income.

We capitalize
interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2007, 2006 and 2005 was $14.3 million, $1.2 million and $0.8 million, respectively. Capitalized interest is recorded as a reduction to interest
expense.

Regulated properties are stated at cost, which includes the equity portion of AFUDC. The equity portion of AFUDC represents the capitalization of
the estimated average cost of equity used during the construction of major projects and is recorded as a credit to the allowance for equity funds used during construction. Generally, the cost of property retired or sold, plus removal costs, less
salvage, is charged to accumulated depreciation.

The average depreciation rates for our regulated property are set forth in the following table for the
periods indicated.



|                              |  |                          |  |      |  |      |  | 
|----------------------------- |  | ------------------------ |  | ---- |  | ---- |  | 
|                              |  | Years Ended December 31, |  |     
|Regulated Property            |  | 2007                     |  | 2006 |  | 2005 |  | 
|Natural Gas Pipelines         |  | 2.4%                     |  | 2.4% |  | 2.7% |  | 
|Natural Gas Liquids Pipelines |  | 2.5%                     |  | 2.6% |  | 2.7% |  | 

Income Taxes - We are not a taxable entity for federal income tax purposes. As such, we do not directly pay
federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in our Consolidated Statements of Income, is included in the federal income tax returns of each partner. The aggregate difference in
the basis of our net assets for financial and income tax purposes cannot be readily determined, as we do not have access to all information about each partners tax attributes related to us.

Our corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for using the provisions of Statement 109, Accounting for
Income Taxes. Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items based on income tax laws and rates existing at the time the temporary
differences are expected to reverse. Except for the companies whose accounting policies conform to Statement 71, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the
enactment date of the rate change. For the companies whose accounting policies conform to Statement 71, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the
period that includes the enactment date.

In June 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes - An Interpretation of
FASB Statement No. 109, which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a
recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized
tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. During 2007, we had no tax positions that would require establishment of a reserve under FIN 48.

We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada.
No returns are currently under audit, and no extensions of statute of limitations have been requested or granted.

Environmental Expenditures - We
accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than
completion of the remediation feasibility study. Such accruals are adjusted as further information becomes available or as circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their
receipt is deemed probable.



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Inventory, Natural Gas Imbalances and Commodity Exchanges - Inventory is valued at the lower of cost or market.
The values of current natural gas and NGLs in storage are determined using the lower of cost or market method. Noncurrent natural gas is classified as property and valued at cost. Materials and supplies are valued at average cost. Natural gas
imbalances and NGL exchanges are valued at market or their contractually stipulated rate. Imbalances and NGL exchanges are settled in cash or made up in kind, subject to the terms of the pipelines tariffs or by agreement.

Other

Fair Value Measurements - In September 2006, the FASB
issued Statement 157, Fair Value Measurements, which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157
as allowed by FASB Staff Position (FSP) 157-2, which delayed the effective date of Statement 157 for nonfinancial assets and liabilities. As of January 1, 2008, we have applied the provisions of Statement 157 to our financial instruments and
the impact was not material. Under FSP 157-2, we will be required to apply Statement 157 to our nonfinancial assets and liabilities beginning January 1, 2009. We are currently reviewing the applicability of Statement 157 to our nonfinancial
assets and liabilities as well as the potential impact on our consolidated financial statements.

In February 2007, the FASB issued Statement 159,
The Fair Value Option for Financial Assets and Financial Liabilities, which allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair
value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159 and therefore there was no impact to our consolidated
financial statements.

Business Combinations - In December 2007, the FASB issued Statement 141R, Business Combinations, which will
require most identifiable assets, liabilities, noncontrolling interest (previously referred to as minority interests) and goodwill acquired in a business combination to be recorded at full fair value. Statement 141R is effective for our year
beginning January 1, 2009, and will be applied prospectively. We are currently reviewing the applicability of Statement 141R to our operations and its potential impact on our consolidated financial statements.

Noncontrolling Interests - In December 2007, the FASB issued Statement 160, Noncontrolling Interest in Consolidated Financial Statements - an amendment to
ARB No. 51, which requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity. Statement 160 is effective for our year beginning January 1, 2009, and will require
retroactive adoption of the presentation and disclosure requirements for existing minority interests. We are currently reviewing the applicability of Statement 160 to our operations and its potential impact on our consolidated financial statements.

Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2007 presentation. These
reclassifications did not impact previously reported net income or partners equity.



|B. | 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 Energy Partners, L.P. (Kinder Morgan) for approximately $300
million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627
miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and
is the managing partner of the Heartland joint venture, which consists primarily of three refined petroleum products terminals and connecting pipelines. Financing for this transaction came from the proceeds of our September 2007 issuance of $600
million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note G for a discussion on the 2037 Notes. The working capital settlement has not been finalized; however, we do not expect material adjustments.

Overland Pass Pipeline Company - In May 2006, we entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture
called Overland Pass Pipeline Company. Overland Pass Pipeline Company 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 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



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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. 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.

The 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). As part of the ONEOK Transactions, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of
TransCanada that held a 0.35 percent general partner interest in us, under a Purchase and Sale Agreement between an affiliate of ONEOK and an affiliate of TransCanada. As a result, ONEOK owns our entire 2 percent general partner interest and
controls us.

We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately
36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited
partner units, which, when combined with its general partner interest, 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.

In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, Determining Whether a
General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and
therefore should consolidate the partnership in the financial statements of the general partner. Our Partnership Agreement provides for the right to replace the general partner by a vote of 66-2/3percent of the outstanding units, excluding units held by the general partner and its affiliates. Under the guidance in EITF 04-5, ONEOK is deemed to have control for accounting
purposes. ONEOK elected to use the prospective method and began to consolidate our operations in their consolidated financial statements as of January 1, 2006. As ONEOK is deemed to control us under the requirements of EITF 04-5, the ONEOK
Transactions were accounted for as a transaction between entities under common control and these transactions were excluded from the accounting prescribed by Statement 141, Business Combinations. Accordingly, ONEOKs historical cost
basis in the ONEOK Energy Assets was transferred to us in a manner similar to a pooling of interests. The difference between the historical cost basis of the net assets acquired of $2.7 billion and the cash paid was assigned to the value of the
Class B limited partner units issued to ONEOK and its general partner interest in us. These assets and their related operations are included in our consolidated financial statements retroactive to January 1, 2006.

Since the ONEOK Transactions were not completed until April 2006, the income and cash flow from the ONEOK Energy Assets for the first quarter of 2006 were retained by
ONEOK. In our 2006 Consolidated Statement of Cash Flows, we reported cash flow retained by ONEOK of $177.5 million, which represents the cash flows generated from these companies while they were owned by ONEOK.



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The following table shows the impact to our Consolidated Statements of Income for the ONEOK Energy Assets prior to our
acquisition.



|                                                      |  |                                  |           |   |  | 
|----------------------------------------------------- |  | -------------------------------- | --------- | - |  | 
|ONEOK Energy Assets                                   |  | Three Months EndedMarch 31, 2006 |           |   | 
|                                                      |  | (Thousands of dollars)           |           |   | 
|Operating revenue                                     |  | $                                | 1,162,571 |   |  | 
|Cost of sales and fuel                                |  |                                  | 1,013,851 |   |  | 
|Net margin                                            |  |                                  | 148,720   |   |  | 
|Operating expenses:                                   |  |                                  |           |   |  | 
|Operations and maintenance                            |  |                                  | 47,530    |   |  | 
|Depreciation and amortization                         |  |                                  | 19,277    |   |  | 
|Taxes other than income                               |  |                                  | 4,407     |   |  | 
|Total operating expenses                              |  |                                  | 71,214    |   |  | 
|Operating income                                      |  |                                  | 77,506    |   |  | 
|Interest expense                                      |  |                                  | 21,281    |   |  | 
|Other income, net                                     |  |                                  | 1,760     |   |  | 
|Income from continuing operations before income taxes |  |                                  | 57,985    |   |  | 
|Income taxes                                          |  |                                  | 22,167    |   |  | 
|Net income                                            |  | $                                | 35,818    |   |  | 
|                                                     
|Limited partners interest in net income:             |  |                                  |           |   |  | 
|Net income                                            |  | $                                | 35,818    |   |  | 
|General partner interest in net income                |  |                                  | (35,818   | ) |  | 
|Limited partners interest in net income              |  | $                                | -         |   |  | 
|                                                     

Prior to the acquisition, the ONEOK Energy Assets were included in the consolidated state and federal income tax
returns of ONEOK and, accordingly, current taxes payable were allocated to the ONEOK Energy Assets based on ONEOKs effective tax rate. Income tax liabilities and provisions for income tax expense for the ONEOK Energy Assets were calculated on
a stand-alone basis. Our Consolidated Statements of Income for 2006 includes income tax expense recorded for the ONEOK Energy Assets of $22.2 million for the first quarter of 2006. In conjunction with the ONEOK Transactions, all income tax
liabilities of ONEOK Energy Assets at the time of the ONEOK Transactions were retained by ONEOK.

Income from the ONEOK Energy Assets for the first quarter
of 2006 also reflects interest expense of $21.3 million, which represents interest charged on long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOKs weighted average cost of debt. This debt
was retained by ONEOK as part of the ONEOK Transactions.

Under the terms of the ONEOK Transactions, we recorded a $72.6 million purchase price adjustment
related to a finalized working capital settlement. The working capital settlement is reflected as an increase to the value of the Class B units and was approved by our Audit Committee.

The unaudited pro forma information in the table below presents a summary of our results of operations as if the acquisition of the ONEOK Energy Assets had occurred at the beginning of the periods presented. The
results do not necessarily reflect the results that would have been obtained if the acquisition of the ONEOK Energy Assets had actually occurred on the dates indicated or results that may be expected in the future.



|                                  |  |                                      |           |  | 
|--------------------------------- |  | ------------------------------------ | --------- |  | 
|                                  |  | Pro FormaYear EndedDecember 31, 2005 |           | 
|                                  |  | (Thousands of dollars)               |           | 
|Revenue                           |  | $                                    | 4,102,335 |  | 
|Income from continuing operations |  | $                                    | 314,471   |  | 
|Net income per unit               |  | $                                    | 3.51      |  | 

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.



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At a special meeting of the holders of our common units held March 29, 2007, the unitholders approved a proposal to
permit the conversion of all or a portion of the Class B limited partner units issued in the ONEOK Transactions into common units on a one-for-one basis at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned
to May 10, 2007, to allow unitholders additional time to vote on an additional proposal to approve amendments to our Partnership Agreement, which, had the amendments been approved, would have granted voting rights for units held by our general
partner and its affiliates if a vote was held to remove our general partner and would have required fair market value compensation for the general partner interest if the general partner was removed. While a majority of our common unitholders voted
in favor of the proposed amendments to our Partnership Agreement at the reconvened meeting of our common unitholders held May 10, 2007, the proposed amendments 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, the Class B limited partner units are entitled to receive increased quarterly distributions equal to 110
percent of the distributions paid with respect to our common units.

On June 21, 2007, ONEOK, as the sole holder of our Class B limited partner units,
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. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after the 90 days following delivery of the notice.

In addition, since the proposed amendments to our Partnership Agreement were not approved by 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.

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. Under Statement 94, Consolidation of All Majority Owned Subsidiaries, a majority-owned subsidiary is not consolidated if control is likely to be temporary or if it does not
rest with the majority owner. Neither we nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipelines Management Committee. Our interest in Northern Border Pipeline has been accounted
for as an investment under the equity method applied on a retroactive basis to January 1, 2006.

Acquisition of Guardian Pipeline Interests - In April 2006, we acquired the 66-2/3percent 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. Following the
completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.



|C. | DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
|-- | ---------------------------------------------

We utilize financial
instruments to reduce our market risk exposure to interest rate and commodity price fluctuations, and to achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our financial
instrument activities. We do not use these instruments for trading purposes.

Cash Flow Hedges - Our Natural Gas Gathering and Processing segment
periodically enters into commodity derivative contracts and fixed-price physical contracts. Our Natural Gas Gathering and Processing segment primarily utilizes NYMEX-based futures, collars and over-the-counter swaps, which are designated as cash
flow hedges, to hedge its exposure to volatility in the price of natural gas, NGLs and condensate and the gross processing spread. At December 31, 2007, the accompanying Consolidated Balance Sheet reflected an unrealized loss of $16.4 million
in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities, all of which will be recognized over the next 12 months. Net gains and losses related to the ineffective portion
of our hedges are reclassified out of accumulated other comprehensive income (loss) to operating revenues in the period the ineffectiveness occurs. Ineffectiveness related to these cash flow hedges was not material in 2007 or 2005. Ineffectiveness
related to these cash flow hedges resulted in a gain of approximately $4.5 million for 2006. There were no gains or losses during 2007, 2006 or 2005 due to the discontinuance of cash flow hedge treatment.



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Fair Value Hedges - In 2007 and prior years we terminated various interest rate swap agreements. The net savings
from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2007 for all terminated swaps was $3.7 million, and the remaining net savings for
all terminated swaps will be recognized over the following periods.



|           |  |                       |     |  | 
|---------- |  | --------------------- | --- |  | 
|           |  |                       |     | 
|           |  | (Millions of dollars) |     | 
|2008       |  | $                     | 3.7 |  | 
|2009       |  |                       | 3.7 |  | 
|2010       |  |                       | 3.7 |  | 
|2011       |  |                       | 0.9 |  | 
|2012       |  |                       | -   |  | 
|Thereafter |  |                       | -   |  | 

At December 31, 2007, none of the interest on our fixed-rate debt was swapped to floating using interest-rate
swaps.



|D. | GOODWILL AND INTANGIBLE ASSETS
|-- | ------------------------------

Goodwill

Activity - There was no change in the carrying amounts of goodwill during 2007. The following table reflects the changes in the carrying amount of goodwill for the
period indicated.



|                                               |  |                          |         |           |   |             |  |   |                          |   |  |   |         |  | 
|---------------------------------------------- |  | ------------------------ | ------- | --------- | - | ----------- |  | - | ------------------------ | - |  | - | ------- |  | 
|                                               |  | BalanceDecember 31, 2005 |         | Additions |   | Adjustments |  |   | BalanceDecember 31, 2006 |   | 
|                                               |  | (Thousands of dollars)   |         |          
|Natural Gas Gathering and Processing           |  | $                        | 75,532  |           | $ | 14,505      |  | $ | -                        |   |  | $ | 90,037  |  | 
|Natural Gas Pipelines                          |  |                          | 68,872  |           |   | 60,125      |  |   | -                        |   |  |   | 128,997 |  | 
|Natural Gas Liquids Gatheringand Fractionation |  |                          | -       |           |   | 175,566     |  |   | -                        |   |  |   | 175,566 |  | 
|Other                                          |  |                          | 8,378   |           |   | -           |  |   | (8,378                   | ) |  |   | -       |  | 
|Goodwill                                       |  | $                        | 152,782 |           | $ | 250,196     |  | $ | (8,378                   | ) |  | $ | 394,600 |  | 
|                                              

The acquisition of the ONEOK Energy Assets resulted in $214.8 million of additional goodwill on our 2006
Consolidated Balance Sheet.

Our acquisition of the 66-2/3percent interest in Guardian Pipeline not previously owned by us resulted in the recognition of $5.7 million of additional goodwill and reclassification of $1.7 million
to goodwill, which had been previously included in our investment in unconsolidated affiliates.

Goodwill increased by approximately $27.9 million
in 2006 relating to the 2003 acquisition of Viking Gas Transmission. In our accounting for the acquisition, we had allocated the entire purchase price to the fair value of the tangible assets including plant in
service. Since that date, we have determined that the amount of purchase price representing a premium over Viking Gas Transmissions historic rate base is not being recovered in its rates and, accordingly, should be accounted for as
goodwill under Statement 142.

See Black Mesa section of this Note for discussion of goodwill impairment.

Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is
referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of December 31, 2007 and 2006.

Impairment Test - We apply the provisions of Statement 142, Goodwill and Other Intangible Assets, and perform our annual impairment test on
July 1. There were no impairment charges resulting from the July 1, 2007, impairment testing, and no events indicating an impairment have occurred subsequent to that date.

Black Mesa - Black Mesa, which is included in our Other segment, includes a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in
Kayenta, Arizona, and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave



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and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the
Navajo Nation and Hopi Tribe joint-use area until December 31, 2005.

Under a consent decree, Mohave agreed to install pollution control equipment by
December 2005. However, due to the uncertainty surrounding ongoing water and coal supply negotiations, Southern California Edison Company (SCE), a 56 percent owner of Mohave, filed a petition before the California Public Utilities Commission (CPUC)
requesting that they either recognize the end of Mohaves coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to
make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.

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

During 2006, we reassessed
our coal slurry pipeline operation as a result of the developments described above. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced, and a goodwill and asset impairment of $8.4 million and $3.6 million,
respectively, was recorded as depreciation and amortization. The reduction to net income after income taxes was $10.6 million.

Intangible Assets

Our intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from ONEOK and are being
amortized over an aggregate weighted-average period of 40 years. Amortization expense for both 2007 and 2006 was $7.7 million, and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The
following tables reflect the gross carrying amount and accumulated amortization of intangible assets for the periods presented.



|                                                |  |                        |         |                         |   |         |                     |  |   |         |  | 
|----------------------------------------------- |  | ---------------------- | ------- | ----------------------- | - | ------- | ------------------- |  | - | ------- |  | 
|                                                |  | December 31, 2007      |         |                        
|                                                |  | GrossIntangibleAssets  |         | AccumulatedAmortization |   |         | NetIntangibleAssets |  |  
|                                                |  | (Thousands of dollars) |         |                        
|Natural Gas Liquids Gathering and Fractionation |  | $                      | 292,000 |                         | $ | (18,249 | )                   |  | $ | 273,751 |  | 
|Natural Gas Liquids Pipelines                   |  |                        | 14,650  |                         |   | (917    | )                   |  |   | 13,733  |  | 
|Intangible Assets                               |  | $                      | 306,650 |                         | $ | (19,166 | )                   |  | $ | 287,484 |  | 
|                                               
|                                                |  |                       
|                                                |  | December 31, 2006      |         |                        
|                                                |  | GrossIntangibleAssets  |         | AccumulatedAmortization |   |         | NetIntangibleAssets |  |  
|                                                |  | (Thousands of dollars) |         |                        
|Natural Gas Liquids Gathering and Fractionation |  | $                      | 292,000 |                         | $ | (10,949 | )                   |  | $ | 281,051 |  | 
|Natural Gas Liquids Pipelines                   |  |                        | 14,650  |                         |   | (550    | )                   |  |   | 14,100  |  | 
|Intangible Assets                               |  | $                      | 306,650 |                         | $ | (11,499 | )                   |  | $ | 295,151 |  | 
|                                               

E. PARTNERS EQUITY

At December 31, 2007, we had 46,397,214 common units and 36,494,126 Class B Units issued and outstanding. ONEOK owns all of the Class B Units, approximately 500,000 common units, and the 2 percent general partner
interest in us. The Class B Units, common units and the general partner interest held by ONEOK and its affiliates together constitute a 45.7 percent interest in us.

Under our Partnership Agreement, in conjunction with the issuance of additional common units, our general partner is required to make equity contributions to us in order to maintain a 2 percent general partner
interest.

Under our Partnership Agreement, we make distributions to our partners with respect to each calendar quarter in an amount equal to 100 percent
of our available cash within 45 days following the end of each quarter. Available cash generally consists of all our cash receipts adjusted for our cash disbursements and net changes to cash reserves. Available cash will



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generally be distributed 98 percent to limited partners and 2 percent to our general partner. As an incentive, the general partners percentage interest
in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the general partner receives:

| |  |  | 15 percent of amounts distributed in excess of $0.605 per common unit,
| | - |  | ----------------------------------------------------------------------

| |  |  | 25 percent of amounts distributed in excess of $0.715 per unit, and
| | - |  | -------------------------------------------------------------------

| |  |  | 50 percent of amounts distributed in excess of $0.935 per unit.
| | - |  | ---------------------------------------------------------------

Our income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions
that are allocated to the general partner. For the years ended December 31, 2007, 2006 and 2005, incentive distributions allocated to the general partners totaled $50.6 million, $31.6 million and $8.0 million, respectively.

F. CREDIT FACILITIES

2007 Partnership Credit Agreement - In
March 2007, we amended and restated our revolving credit facility agreement (2007 Partnership Credit Agreement) with several banks and other financial institutions and lenders in the following principal ways: (i) revised the pricing,
(ii) extended the maturity by one year to March 2012, (iii) eliminated the interest coverage ratio covenant, (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1), (v) increased the swingline
sub-facility commitments from $15 million to $50 million and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of our consolidated indebtedness. The interest rates applicable to extensions of credit
under this agreement are based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the
Eurodollar rate plus a set number of basis points, depending on our current long-term unsecured debt ratings.

In July 2007, we exercised the accordion
feature of our 2007 Partnership Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion.

In December 2006, we
amended our 2007 Partnership Credit Agreement (previously referred to as the 2006 Partnership Credit Agreement). This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total
capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA
(net income before interest expense, income taxes and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland
Pass Pipeline Company agreement from the covenant that limits our ability to enter into agreements that restrict our ability to grant liens to the lenders under the 2007 Partnership Credit Agreement.

Under the 2007 Partnership Credit Agreement, we are required to comply with certain financial, operational and legal covenants. Among other things, these requirements
include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for any approved capital projects) of no more than 5 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the
allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisition.

Upon breach of
any covenant, discussed above, amounts outstanding under the 2007 Partnership Credit Agreement may become immediately due and payable. We were in compliance with these covenants at December 31, 2007. The average interest rate of borrowings
under this agreement was 5.40 percent and 6.75 percent at December 31, 2007 and 2006, respectively. At December 31, 2007, we had $100 million of borrowings outstanding under this agreement and $900 million was available.

In November 2007, we entered into a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million
is being used, and a $12 million Standby Letter of Credit Agreement with Royal Bank of Canada. Both agreements are used to support various permits required by the KDHE for our ongoing business in Kansas.

We had $10 million in letters of credit outstanding at December 31, 2006.

Bridge Facility - In April 2006, we entered into a $1.1 billion 364-day credit agreement (the Bridge Facility) with a syndicate of banks and borrowed $1.05
billion to finance a portion of the acquisition of the ONEOK Energy Assets. In September 2006, we repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being
terminated in accordance with its terms. See Note G for further discussion regarding the issuance of senior notes.



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Guardian Pipeline - The Guardian Pipeline revolving credit agreement permitted us to choose rates based on the
prime commercial lending rate or LIBOR as the interest rate on its outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and specify the interest rate period. The Guardian Pipeline revolving
credit agreement terminated in November 2007.

G. LONG-TERM DEBT

The following table sets forth our long-term debt for the periods indicated. All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior
indebtedness.



|                                    |  |                        |           |   |                  |   |           |   |  | 
|----------------------------------- |  | ---------------------- | --------- | - | ---------------- | - | --------- | - |  | 
|                                    |  | December 31,2007       |           |   | December 31,2006 |   |           |  
|                                    |  | (Thousands of dollars) |           |   |                 
|ONEOK Partners                      |  |                        |           |   |                  |  
|$250,000 at 8.875% due 2010         |  | $                      | 250,000   |   |                  | $ | 250,000   |   |  | 
|$225,000 at 7.10% due 2011          |  |                        | 225,000   |   |                  |   | 225,000   |   |  | 
|$350,000 at 5.90% due 2012          |  |                        | 350,000   |   |                  |   | 350,000   |   |  | 
|$450,000 at 6.15% due 2016          |  |                        | 450,000   |   |                  |   | 450,000   |   |  | 
|$600,000 at 6.65% due 2036          |  |                        | 600,000   |   |                  |   | 600,000   |   |  | 
|$600,000 at 6.85% due 2037          |  |                        | 600,000   |   |                  |   | -         |   |  | 
|                                    |  |                        |           |   |                  |   |           |   |  | 
|                                    |  |                        | 2,475,000 |   |                  |   | 1,875,000 |   |  | 
|                                    |  |                        |           |   |                  |   |           |   |  | 
|Guardian Pipeline                   |  |                        |           |   |                  |   |           |   |  | 
|Average 7.85% due 2022              |  |                        | 133,641   |   |                  |   | 145,572   |   |  | 
|                                    |  |                        |           |   |                  |   |           |   |  | 
|Total long-term notes payable       |  |                        | 2,608,641 |   |                  |   | 2,020,572 |   |  | 
|Change in fair value of hedged debt |  |                        | 12,155    |   |                  |   | 12,310    |   |  | 
|Unamortized debt premium            |  |                        | (3,470    | ) |                  |   | (1,353    | ) |  | 
|Current maturities                  |  |                        | (11,930   | ) |                  |   | (11,931   | ) |  | 
|Long-term debt                      |  | $                      | 2,605,396 |   |                  | $ | 2,019,598 |   |  | 
|                                   

The aggregate maturities of long-term debt outstanding for years 2008 through
2012 are shown below.



|     |  |                       |       |                  |   |       |  |   |       |  | 
|---- |  | --------------------- | ----- | ---------------- | - | ----- |  | - | ----- |  | 
|     |  | ONEOKPartners         |       | GuardianPipeline |   | Total |  |  
|     |  | (Millions of dollars) |       |                 
|2008 |  | $                     | -     |                  | $ | 11.9  |  | $ | 11.9  |  | 
|2009 |  |                       | -     |                  |   | 11.9  |  |   | 11.9  |  | 
|2010 |  |                       | 250.0 |                  |   | 11.9  |  |   | 261.9 |  | 
|2011 |  |                       | 225.0 |                  |   | 11.9  |  |   | 236.9 |  | 
|2012 |  |                       | 350.0 |                  |   | 11.1  |  |   | 361.1 |  | 

2007 Debt Issuance - In September 2007, we completed an underwritten public offering of $600 million
aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under our existing shelf registration statement filed with the SEC.

We may redeem the 2037 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the 2037 Notes, plus accrued and unpaid interest and a make-whole premium.
The redemption price will never be less than 100 percent of the principal amount of the 2037 Notes plus accrued and unpaid interest. The 2037 Notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and
future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of our non-guarantor subsidiaries. The 2037 Notes are non-recourse to our general partner.

The net proceeds from the 2037 Notes, after deducting underwriting discounts and commissions and expenses, of $592.9 million were used to finance our $300 million
acquisition, before working capital adjustments, of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan and to repay debt outstanding under the 2007 Partnership
Credit Agreement.



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The terms of the 2037 Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners
and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fourth Supplemental Indenture, dated September 28, 2007 (Indenture). The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides
that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and sell and lease back
our property.

The 2037 Notes will mature on October 15, 2037. We will pay interest on the 2037 Notes on April 15 and October 15 of each
year. The first payment of interest on the 2037 Notes will be made on April 15, 2008. Interest on the 2037 Notes accrues from September 28, 2007, which was the issuance date of the 2037 Notes.

2006 Debt Issuance - In September 2006, we completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior
Notes due 2012 (the 2012 Notes), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the 2016 Notes) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the 2036 Notes
and collectively with the 2012 Notes and the 2016 Notes, the Notes). We registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006.

We may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest
and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with
all of our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of our non-guarantor subsidiaries. The Notes are non-recourse to our general partner.

The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses but before offering expenses, were
used to repay all of the $1.05 billion outstanding under our Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated
September 25, 2006, between us and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third
Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time
to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets, and sell and lease back our property.

The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016 and October 1, 2036, respectively. We will pay interest on
the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes was made on April 1, 2007. Interest on the Notes accrued from September 25, 2006, which was the issuance date of the Notes.

Debt Covenants - We have debt covenants in addition to the covenants discussed in 2007 Debt Issuance and 2006 Debt Issuance above. Our
$250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require us to offer to repurchase the senior notes at par value if our Moodys or S&P credit rating falls below investment grade
(Baa3 for Moodys or BBB- for S&P) and the investment grade rating is not reinstated within a period of 40 days. Further, the indentures governing our senior notes due 2010 and 2011 include an event of default upon acceleration of other
indebtedness of $25 million or more and the indentures governing our senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer
to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable
in full.

Debt Guarantee - The 2037 Notes and the Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Intermediate
Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnerships existing and future unsecured senior indebtedness. We have no significant assets or operations other than our investment in our wholly owned
subsidiary, the Intermediate Partnership, which is also consolidated. The Intermediate Partnership holds partnership interests and the equity in our subsidiaries as well as a 50 percent interest in Northern Border Pipeline at December 31, 2007,
which is accounted for under the equity method.

The Northern Border Pipeline partnership agreement provides that distributions to Northern Border
Pipelines partners are to be made on a pro rata basis according to each partners percentage interest. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension
of, the cash distribution



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policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100
percent of distributable cash flow as determined from Northern Border Pipelines financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Loans or
other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement. After we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006, the
Northern Border Pipeline Management Committee adopted certain changes to its cash distribution policy related to financial ratio targets and capital contributions. The change was to define minimum equity to total capitalization ratios to be used by
the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions. At
December 31, 2007 and 2006, our equity in the net assets of Northern Border Pipeline was approximately $419 million and $438 million, respectively.

Guardian Pipeline Senior Notes - These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the $133.6 million in notes outstanding
at December 31, 2007, range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent. Guardian Pipelines senior notes contain financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus
interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDAR of not greater than 5.75 to
1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2007, Guardian Pipeline was in compliance with its financial covenants.

Other

Fair Value - The following estimated fair values
represent the amount at which debt could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the aggregate of all
the senior notes outstanding was approximately $2.7 billion and $2.0 billion at December 31, 2007 and 2006, respectively. We presently intend to maintain the current schedule of maturities for the senior notes, which will result in no gains or
losses on their respective repayment. The fair value of the 2007 Partnership Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.

Unamortized Debt Premium, Discount and Expense-We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt
consistent with the terms of the respective debt instrument.

H. COMMITMENTS AND CONTINGENCIES

Operating Leases - Future minimum lease payments under non-cancelable operating leases on a gas processing plant, storage contracts, office space, pipeline
equipment, rights-of-way and vehicles are shown in the table below.



|     |  |                       |      |  | 
|---- |  | --------------------- | ---- |  | 
|     |  |                       |      | 
|     |  | (Millions of dollars) |      | 
|2008 |  | $                     | 18.7 |  | 
|2009 |  |                       | 13.8 |  | 
|2010 |  |                       | 12.7 |  | 
|2011 |  |                       | 12.6 |  | 
|2012 |  |                       | 5.8  |  | 

Firm Transportation Obligations and Other Commitments - We have firm transportation agreements with Fort
Union Gas Gathering and Lost Creek Gathering Company. The Fort Union Gas Gathering agreement expires in 2009, and the Lost Creek Gathering Company agreement expires in 2010. Under these agreements, we must make specified minimum payments to Fort
Union Gas Gathering and Lost Creek Gathering Company each month. We recorded expenses of $11.9 million, $12.0 million and $11.7 million for 2007, 2006 and 2005, respectively, related to these agreements. At December 31, 2007, the estimated
aggregate amounts of such required future payments were $11.9 million for 2008, $11.3 million for 2009 and $3.7 million for 2010.

Environmental
Liabilities - We are subject to multiple environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous materials, and
substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations,
permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be



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material to our results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of
transporting natural gas, NGLs, or refined products, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could
materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot
assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating
restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2007, 2006 or 2005
related to compliance with environmental regulations.

Legal Proceedings - We are a party to various litigation matters and claims that are in the
normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial
position or liquidity.

Other - As a result of an internal review of a transaction that was brought to the attention of one of our affiliates by a
third party, we have commenced an internal review of transactions that may have violated FERC capacity release rules or related rules. We have notified the FERC of this review and expect to file a report with the FERC by mid-March 2008 concerning
any violations. At this time, we do not believe that penalties, if any, associated with potential violations will have a material impact on our results of operations, financial position or liquidity.

I. INCOME TAXES

Components of the income tax provision applicable to
continuing operations and income taxes paid by our corporate subsidiaries are shown in the table below.



|                              |  |                          |       |      |   |        |  |   |       |  | 
|----------------------------- |  | ------------------------ | ----- | ---- | - | ------ |  | - | ----- |  | 
|                              |  | Years Ended December 31, |       |     
|                              |  | 2007                     |       | 2006 |   | 2005   |  |  
|                              |  | (Thousands of dollars)   |       |     
|Taxes currently payable:      |  |                          |       |      |  
|Federal                       |  | $                        | 72    |      | $ | -      |  | $ | 2,036 |  | 
|State                         |  |                          | 4,203 |      |   | -      |  |   | 390   |  | 
|Total taxes currently payable |  |                          | 4,275 |      |   | -      |  |   | 2,426 |  | 
|Deferred taxes:               |  |                          |       |      |   |        |  |   |       |  | 
|Federal                       |  |                          | 3,994 |      |   | 2,163  |  |   | 2,639 |  | 
|State                         |  |                          | 573   |      |   | 3,339  |  |   | 727   |  | 
|Total deferred taxes          |  |                          | 4,567 |      |   | 5,502  |  |   | 3,366 |  | 
|Taxes retained by ONEOK       |  |                          | -     |      |   | 22,167 |  |   | -     |  | 
|Total tax provision           |  | $                        | 8,842 |      | $ | 27,669 |  | $ | 5,792 |  | 
|                             

Taxes retained by ONEOK represent taxes accrued for the ONEOK Energy Assets during the first quarter of
2006. In conjunction with the ONEOK Transactions, all income tax liabilities of the ONEOK Energy Assets at the time of the ONEOK Transactions were retained by ONEOK. See Note B for additional discussion of the ONEOK Transactions.



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The following table is a reconciliation of our provision for income taxes for the
periods indicated.



|                                         |  |                          |          |   |      |   |          |      |  |   |         |   |  | 
|---------------------------------------- |  | ------------------------ | -------- | - | ---- | - | -------- | ---- |  | - | ------- | - |  | 
|                                         |  | Years Ended December 31, |          |   |     
|                                         |  | 2007                     |          |   | 2006 |   |          | 2005 |  |   |        
|                                         |  | (Thousands of dollars)   |          |   |     
|Pretax income from continuing operations |  | $                        | 416,589  |   |      | $ | 420,849  |      |  | $ | 152,299 |   |  | 
|Federal statutory income tax rate        |  |                          | 35.0     | % |      |   | 35.0     | %    |  |   | 35.0    | % |  | 
|Provision for federal income taxes       |  |                          | 145,806  |   |      |   | 147,297  |      |  |   | 53,305  |   |  | 
|Partnership earnings not subject to tax  |  |                          | (141,884 | ) |      |   | (144,928 | )    |  |   | (48,630 | ) |  | 
|State income taxes                       |  |                          | 4,772    |   |      |   | 2,990    |      |  |   | 1,117   |   |  | 
|Other, net                               |  |                          | 148      |   |      |   | 143      |      |  |   | -       |   |  | 
|Income tax expense                       |  | $                        | 8,842    |   |      | $ | 5,502    |      |  | $ | 5,792   |   |  | 
|                                        

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of
the deferred tax assets and liabilities for the periods indicated.



|                                                   |  |                          |        |   |      |   |       |  | 
|-------------------------------------------------- |  | ------------------------ | ------ | - | ---- | - | ----- |  | 
|                                                   |  | Years Ended December 31, |        |  
|                                                   |  | 2007                     |        |   | 2006 |   |      
|                                                   |  | (Thousands of dollars)   |        |  
|Deferred tax assets:                               |  |                          |        |   |     
|Net operating losses                               |  | $                        | 4,715  |   |      | $ | 7,971 |  | 
|Other                                              |  |                          | 1,596  |   |      |   | 129   |  | 
|Total deferred tax assets                          |  |                          | 6,311  |   |      |   | 8,100 |  | 
|Deferred tax liabilities:                          |  |                          |        |   |      |   |       |  | 
|Excess of tax over book depreciation and depletion |  |                          | 7,934  |   |      |   | 5,414 |  | 
|Regulatory assets                                  |  |                          | 2,544  |   |      |   | 2,526 |  | 
|Other                                              |  |                          | 77     |   |      |   | 79    |  | 
|Total deferred tax liabilities                     |  |                          | 10,555 |   |      |   | 8,019 |  | 
|Net deferred tax assets/ (liabilities)             |  | $                        | (4,244 | ) |      | $ | 81    |  | 
|                                                  

At December 31, 2007, we had approximately $5.0 million of tax benefits available related to net operating
loss carryforwards, which will expire between the years 2022 and 2026. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation
allowance is necessary.

We had income taxes payable of approximately $3.1 million at December 31, 2007. Cash paid for income taxes, net, was
approximately $1.0 million, $0.6 million and $1.4 million at December 31, 2007, 2006 and 2005, respectively.

J. SEGMENTS

Segment Descriptions - 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.

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:

| |  |  | our Natural Gas Gathering and Processing segment primarily gathers and processes raw natural gas,
| | - |  | -------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities,
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs and stores and markets NGL products, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | our Natural Gas Liquids Pipelines segment primarily operates our FERC-regulated interstate natural gas liquids gathering and distribution pipelines.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------



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The acquisition of the ONEOK Energy Assets in April 2006 is accounted for in our consolidated financial statements
effective January 1, 2006. In connection with these transactions, we formed our former natural gas liquids segment and our former pipelines and storage segment.

Accounting Policies - The accounting policies of the segments are described in Note A. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Natural Gas
Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segments revenues are from ONEOK and its subsidiaries that utilize transportation and storage services. Corporate overhead
costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments.

Northern Border Pipeline was no longer consolidated effective January 1, 2006. For our Natural Gas Pipelines segment, Northern Border Pipelines revenues represented approximately 85 percent of the
segments revenues in 2005.

Customers - The main customers for our Natural Gas Gathering and Processing segment are primarily major and
independent oil and gas production companies. Our Natural Gas Liquids Gathering and Fractionation segments customers are primarily natural gas gathering and processing companies and petrochemical, refining and NGL marketing companies.
Companies served by our Natural Gas Pipelines segment include local distribution companies, power generating companies, natural gas marketing companies and petrochemical companies. Our Natural Gas Liquids Pipelines segments customers are
primarily NGL gathering companies, propane distributors and petrochemical and refining companies.

In 2007 and 2006, we had no single external customer
from which we received 10 percent or more of our consolidated revenues. For 2005, we had two customers that accounted for more than 10 percent of our total consolidated operating revenues. In 2005, Lodgepole Energy Marketing (Lodgepole) and BP
Canada accounted for $123.2 million (18 percent) and $114.4 million (16 percent), respectively, of our consolidated operating revenues. Operating revenues from Lodgepole are recorded in our Natural Gas Gathering and Processing segment. Our Natural
Gas Gathering and Processing segment and Natural Gas Pipelines segment have recorded operating revenues from BP Canada.

Operating Segment
Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated. Amounts in prior periods have been restated to conform to our current presentation.



|                                         |  |                                   |           |                          |   |                                             |  |                                 |           |                       |   |           |       |   |          |   |  |   |           |  | 
|---------------------------------------- |  | --------------------------------- | --------- | ------------------------ | - | ------------------------------------------- |  | ------------------------------- | --------- | --------------------- | - | --------- | ----- | - | -------- | - |  | - | --------- |  | 
|Year EndedDecember 31, 2007              |  | Natural GasGatheringandProcessing |           | Natural GasPipelines (a) |   | Natural GasLiquidsGatheringandFractionation |  | Natural GasLiquidsPipelines (b) |           | Other andEliminations |   |           | Total |   |         
|                                         |  | (Thousands of dollars)            |           |                         
|Sales to unaffiliated customers          |  | $                                 | 433,139   |                          | $ | 194,170                                     |  | $                               | 4,562,178 |                       | $ | 15,280    |       | $ | 27       |   |  | $ | 5,204,794 |  | 
|Sales to affiliated customers            |  |                                   | 519,755   |                          |   | 107,009                                     |  |                                 | -         |                       |   | -         |       |   | -        |   |  |   | 626,764   |  | 
|Intersegment sales                       |  |                                   | 505,756   |                          |   | 785                                         |  |                                 | 25,115    |                       |   | 76,555    |       |   | (608,211 | ) |  |   | -         |  | 
|Operating revenue                        |  | $                                 | 1,458,650 |                          | $ | 301,964                                     |  | $                               | 4,587,293 |                       | $ | 91,835    |       | $ | (608,184 | ) |  | $ | 5,831,558 |  | 
|Gain on sale of assets                   |  | $                                 | 1,825     |                          | $ | 79                                          |  | $                               | 39        |                       | $ | 7         |       | $ | -        |   |  | $ | 1,950     |  | 
|Operating income                         |  | $                                 | 187,815   |                          | $ | 112,212                                     |  | $                               | 111,976   |                       | $ | 39,460    |       | $ | (4,680   | ) |  | $ | 446,783   |  | 
|Equity earnings from investments         |  | $                                 | 26,399    |                          | $ | 62,487                                      |  | $                               | -         |                       | $ | 1,022     |       | $ | -        |   |  | $ | 89,908    |  | 
|EBITDA                                   |  | $                                 | 259,246   |                          | $ | 207,196                                     |  | $                               | 134,393   |                       | $ | 53,411    |       | $ | 2,872    |   |  | $ | 657,118   |  | 
|Investments in unconsolidated affiliates |  | $                                 | 298,701   |                          | $ | 426,992                                     |  | $                               | -         |                       | $ | 30,567    |       | $ | -        |   |  | $ | 756,260   |  | 
|Total assets                             |  | $                                 | 1,564,697 |                          | $ | 1,164,111                                   |  | $                               | 1,881,397 |                       | $ | 1,214,833 |       | $ | 287,027  |   |  | $ | 6,112,065 |  | 
|Capital expenditures                     |  | $                                 | 83,820    |                          | $ | 138,919                                     |  | $                               | 123,555   |                       | $ | 363,460   |       | $ | 104      |   |  | $ | 709,858   |  | 

|(a) - | Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segments regulated operations had revenues of $252.5 million and
operating income of $82.9 million for 2007.
|----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(b) - | All of our Natural Gas Liquids Pipelines segments operations are regulated.
|----- | ----------------------------------------------------------------------------



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|                                                                                                                                                                                                                                                                                                                                                                         |  |                                    |           |                          |   |                                              |  |   |                                 |   |                       |   |         |       |   |          |   |  |   |           |  | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ---------------------------------- | --------- | ------------------------ | - | -------------------------------------------- |  | - | ------------------------------- | - | --------------------- | - | ------- | ----- | - | -------- | - |  | - | --------- |  | 
|Year Ended December 31, 2006                                                                                                                                                                                                                                                                                                                                             |  | Natural GasGathering andProcessing |           | Natural GasPipelines (a) |   | Natural GasLiquidsGathering andFractionation |  |   | Natural GasLiquidsPipelines (b) |   | Other andEliminations |   |         | Total |   |         
|                                                                                                                                                                                                                                                                                                                                                                         |  | (Thousands of dollars)             |           |                         
|Sales to unaffiliated customers                                                                                                                                                                                                                                                                                                                                          |  | $                                  | 478,848   |                          | $ | 195,063                                      |  | $ | 3,467,048                       |   |                       | $ | -       |       | $ | 1,587    |   |  | $ | 4,142,546 |  | 
|Sales to affiliated customers                                                                                                                                                                                                                                                                                                                                            |  |                                    | 476,361   |                          |   | 121,088                                      |  |   | (1,747                          | ) |                       |   | -       |       |   | -        |   |  |   | 595,702   |  | 
|Intersegment sales                                                                                                                                                                                                                                                                                                                                                       |  |                                    | 520,881   |                          |   | 857                                          |  |   | 27,675                          |   |                       |   | 66,496  |       |   | (615,909 | ) |  |   | -         |  | 
|Operating revenue                                                                                                                                                                                                                                                                                                                                                        |  | $                                  | 1,476,090 |                          | $ | 317,008                                      |  | $ | 3,492,976                       |   |                       | $ | 66,496  |       | $ | (614,322 | ) |  | $ | 4,738,248 |  | 
|Gain on sale of assets                                                                                                                                                                                                                                                                                                                                                   |  | $                                  | 373       |                          | $ | 114,890                                      |  | $ | 47                              |   |                       | $ | 7       |       | $ | 166      |   |  | $ | 115,483   |  | 
|Operating income                                                                                                                                                                                                                                                                                                                                                         |  | $                                  | 180,615   |                          | $ | 237,330                                      |  | $ | 88,779                          |   |                       | $ | 29,086  |       | $ | (24,598  | ) |  | $ | 511,212   |  | 
|Equity earnings from investments                                                                                                                                                                                                                                                                                                                                         |  | $                                  | 22,616    |                          | $ | 72,835                                       |  | $ | -                               |   |                       | $ | 432     |       | $ | -        |   |  | $ | 95,883    |  | 
|EBITDA                                                                                                                                                                                                                                                                                                                                                                   |  | $                                  | 249,136   |                          | $ | 343,384                                      |  | $ | 109,753                         |   |                       | $ | 41,692  |       | $ | (15,396  | ) |  | $ | 728,569   |  | 
|Investments in unconsolidated affiliates                                                                                                                                                                                                                                                                                                                                 |  | $                                  | 294,308   |                          | $ | 445,339                                      |  | $ | -                               |   |                       | $ | 9,232   |       | $ | -        |   |  | $ | 748,879   |  | 
|Total assets                                                                                                                                                                                                                                                                                                                                                             |  | $                                  | 1,615,969 |                          | $ | 1,224,576                                    |  | $ | 1,522,177                       |   |                       | $ | 511,949 |       | $ | 47,046   |   |  | $ | 4,921,717 |  | 
|Capital expenditures                                                                                                                                                                                                                                                                                                                                                     |  | $                                  | 80,982    |                          | $ | 48,598                                       |  | $ | 21,761                          |   |                       | $ | 49,322  |       | $ | 1,083    |   |  | $ | 201,746   |  | 
|(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations.
Our Natural Gas Pipelines segments regulated operations had revenues of $269.4 million and operating income of $211.0 million, including $113.9 million from a gain on sale of assets, for 2006. (b) - All of our Natural Gas Liquids Pipelines segments operations are regulated.
|                                                                                                                                                                                                                                                                                                                                                                         |  |                                    |           |                          |   |                                              | 
|Year Ended December 31, 2005                                                                                                                                                                                                                                                                                                                                             |  | Natural GasGathering andProcessing |           | Natural GasPipelines (a) |   | Natural GasLiquidsGathering andFractionation |  |   | Natural GasLiquidsPipelines     |   | Other andEliminations |   |         | Total |   |         
|                                                                                                                                                                                                                                                                                                                                                                         |  | (Thousands of dollars)             |           |                         
|Sales to unaffiliated customers                                                                                                                                                                                                                                                                                                                                          |  | $                                  | 275,287   |                          | $ | 396,402                                      |  | $ | -                               |   |                       | $ | -       |       | $ | 24,572   |   |  | $ | 696,261   |  | 
|Sales to affiliated customers                                                                                                                                                                                                                                                                                                                                            |  |                                    | -         |                          |   | 7,683                                        |  |   | -                               |   |                       |   | -       |       |   | -        |   |  |   | 7,683     |  | 
|Intersegment sales                                                                                                                                                                                                                                                                                                                                                       |  |                                    | -         |                          |   | -                                            |  |   | -                               |   |                       |   | -       |       |   | -        |   |  |   | -         |  | 
|Operating revenue                                                                                                                                                                                                                                                                                                                                                        |  | $                                  | 275,287   |                          | $ | 404,085                                      |  | $ | -                               |   |                       | $ | -       |       | $ | 24,572   |   |  | $ | 703,944   |  | 
|Operating income                                                                                                                                                                                                                                                                                                                                                         |  | $                                  | 44,714    |                          | $ | 214,168                                      |  | $ | -                               |   |                       | $ | -       |       | $ | (2,114   | ) |  | $ | 256,768   |  | 
|Equity earnings from investments                                                                                                                                                                                                                                                                                                                                         |  | $                                  | 22,473    |                          | $ | 2,263                                        |  | $ | -                               |   |                       | $ | -       |       | $ | -        |   |  | $ | 24,736    |  | 
|EBITDA                                                                                                                                                                                                                                                                                                                                                                   |  | $                                  | 83,840    |                          | $ | 285,871                                      |  | $ | -                               |   |                       | $ | -       |       | $ | 2,260    |   |  | $ | 371,971   |  | 
|Investments in unconsolidated affiliates                                                                                                                                                                                                                                                                                                                                 |  | $                                  | 254,286   |                          | $ | 36,470                                       |  | $ | -                               |   |                       | $ | -       |       | $ | -        |   |  | $ | 290,756   |  | 
|Total assets                                                                                                                                                                                                                                                                                                                                                             |  | $                                  | 594,379   |                          | $ | 1,888,980                                    |  | $ | -                               |   |                       | $ | -       |       | $ | 44,407   |   |  | $ | 2,527,766 |  | 
|Capital expenditures                                                                                                                                                                                                                                                                                                                                                     |  | $                                  | 16,602    |                          | $ | 39,641                                       |  | $ | -                               |   |                       | $ | -       |       | $ | 3,639    |   |  | $ | 59,882    |  | 



|(a) - | For 2005, all of our Natural Gas Pipelines segments operations are regulated.
|----- | ------------------------------------------------------------------------------



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We evaluate our performance based on EBITDA, which we define as earnings before interest, income taxes, depreciation and
amortization less the cost of the equity component of AFUDC. Management uses EBITDA to compare the financial performance of its segments and to internally manage those business segments. Management believes that EBITDA provides useful information to
investors as a measure of comparison with peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. EBITDA calculations may vary from company to
company, so our computation of EBITDA may not be comparable with a similarly titled measure of another company.

The following tables set forth the
reconciliation of net income to EBITDA by operating segment for the periods indicated.



|                                                    |  |                                    |         |   |                      |   |         |                                              |  |   |                             |   |  |                       |        |   |       |   |          |   |  |   |         |   |  | 
|--------------------------------------------------- |  | ---------------------------------- | ------- | - | -------------------- | - | ------- | -------------------------------------------- |  | - | --------------------------- | - |  | --------------------- | ------ | - | ----- | - | -------- | - |  | - | ------- | - |  | 
|Year Ended December 31, 2007                        |  | Natural GasGathering andProcessing |         |   | Natural GasPipelines |   |         | Natural GasLiquidsGathering andFractionation |  |   | Natural GasLiquidsPipelines |   |  | Other andEliminations |        |   | Total |   |          |  
|                                                    |  | (Thousands of dollars)             |         |   |                     
|Net income                                          |  | $                                  | 222,838 |   |                      | $ | 160,542 |                                              |  | $ | 117,362                     |   |  | $                     | 46,012 |   |       | $ | (139,007 | ) |  | $ | 407,747 |   |  | 
|Minority interests                                  |  |                                    | -       |   |                      |   | 387     |                                              |  |   | -                           |   |  |                       | 29     |   |       |   | -        |   |  |   | 416     |   |  | 
|Interest expense, net                               |  |                                    | (8,720  | ) |                      |   | 11,785  |                                              |  |   | (6,103                      | ) |  |                       | 3,176  |   |       |   | 138,809  |   |  |   | 138,947 |   |  | 
|Depreciation and amortization                       |  |                                    | 45,099  |   |                      |   | 32,380  |                                              |  |   | 23,134                      |   |  |                       | 13,062 |   |       |   | 29       |   |  |   | 113,704 |   |  | 
|Income taxes                                        |  |                                    | 29      |   |                      |   | 5,772   |                                              |  |   | -                           |   |  |                       | -      |   |       |   | 3,041    |   |  |   | 8,842   |   |  | 
|Allowance for equity funds used during construction |  |                                    | -       |   |                      |   | (3,670  | )                                            |  |   | -                           |   |  |                       | (8,868 | ) |       |   | -        |   |  |   | (12,538 | ) |  | 
|EBITDA                                              |  | $                                  | 259,246 |   |                      | $ | 207,196 |                                              |  | $ | 134,393                     |   |  | $                     | 53,411 |   |       | $ | 2,872    |   |  | $ | 657,118 |   |  | 
|                                                   
|                                                    |  |                                    |         |   |                      |   |        
|Year Ended December 31, 2006                        |  | Natural GasGathering andProcessing |         |   | Natural GasPipelines |   |         | Natural GasLiquidsGathering andFractionation |  |   | Natural GasLiquidsPipelines |   |  | Other andEliminations |        |   | Total |   |          |  
|                                                    |  | (Thousands of dollars)             |         |   |                     
|Net income                                          |  | $                                  | 190,701 |   |                      | $ | 269,995 |                                              |  | $ | 77,050                      |   |  | $                     | 24,675 |   |       | $ | (117,235 | ) |  | $ | 445,186 |   |  | 
|Minority interests                                  |  |                                    | -       |   |                      |   | 2,392   |                                              |  |   | -                           |   |  |                       | -      |   |       |   | -        |   |  |   | 2,392   |   |  | 
|Interest expense, net                               |  |                                    | 4,590   |   |                      |   | 26,252  |                                              |  |   | 8,776                       |   |  |                       | 5,422  |   |       |   | 88,442   |   |  |   | 133,482 |   |  | 
|Depreciation and amortization                       |  |                                    | 43,032  |   |                      |   | 32,841  |                                              |  |   | 20,738                      |   |  |                       | 12,035 |   |       |   | 13,399   |   |  |   | 122,045 |   |  | 
|Income taxes                                        |  |                                    | 10,813  |   |                      |   | 12,822  |                                              |  |   | 3,189                       |   |  |                       | 847    |   |       |   | (2       | ) |  |   | 27,669  |   |  | 
|Allowance for equity funds used during construction |  |                                    | -       |   |                      |   | (918    | )                                            |  |   | -                           |   |  |                       | (1,287 | ) |       |   | -        |   |  |   | (2,205  | ) |  | 
|EBITDA                                              |  | $                                  | 249,136 |   |                      | $ | 343,384 |                                              |  | $ | 109,753                     |   |  | $                     | 41,692 |   |       | $ | (15,396  | ) |  | $ | 728,569 |   |  | 
|                                                   
|                                                    |  |                                    |         |   |                      |   |        
|Year Ended December 31, 2005                        |  | Natural GasGathering andProcessing |         |   | Natural GasPipelines |   |         | Natural GasLiquidsGathering andFractionation |  |   | Natural GasLiquidsPipelines |   |  | Other andEliminations |        |   | Total |   |          |  
|                                                    |  | (Thousands of dollars)             |         |   |                     
|Net income                                          |  | $                                  | 67,552  |   |                      | $ | 123,604 |                                              |  | $ | -                           |   |  | $                     | -      |   |       | $ | (44,143  | ) |  | $ | 147,013 |   |  | 
|Minority interests                                  |  |                                    | -       |   |                      |   | 45,674  |                                              |  |   | -                           |   |  |                       | -      |   |       |   | -        |   |  |   | 45,674  |   |  | 
|Interest expense, net                               |  |                                    | 219     |   |                      |   | 44,990  |                                              |  |   | -                           |   |  |                       | -      |   |       |   | 41,694   |   |  |   | 86,903  |   |  | 
|Depreciation and amortization                       |  |                                    | 16,045  |   |                      |   | 67,608  |                                              |  |   | -                           |   |  |                       | -      |   |       |   | 2,708    |   |  |   | 86,361  |   |  | 
|Income taxes                                        |  |                                    | 24      |   |                      |   | 4,522   |                                              |  |   | -                           |   |  |                       | -      |   |       |   | 2,001    |   |  |   | 6,547   |   |  | 
|Allowance for equity funds used during construction |  |                                    | -       |   |                      |   | (527    | )                                            |  |   | -                           |   |  |                       | -      |   |       |   | -        |   |  |   | (527    | ) |  | 
|EBITDA                                              |  | $                                  | 83,840  |   |                      | $ | 285,871 |                                              |  | $ | -                           |   |  | $                     | -      |   |       | $ | 2,260    |   |  | $ | 371,971 |   |  | 
|                                                   



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|K. | UNCONSOLIDATED AFFILIATES
|-- | -------------------------

Investments in Unconsolidated
Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated.



|                                                                                                                                                                                                                                                                                                                                                                                     |  |               |   |  |                        |         |     |      |   |         |     |  | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------- | - |  | ---------------------- | ------- | --- | ---- | - | ------- | --- |  | 
|                                                                                                                                                                                                                                                                                                                                                                                     |  | Net Ownership |   |  | December 31,           |         |     |     
|                                                                                                                                                                                                                                                                                                                                                                                     |  | Interest      |   |  | 2007                   |         |     | 2006 |   |         |    
|                                                                                                                                                                                                                                                                                                                                                                                     |  |               |   |  | (Thousands of dollars) |         |     |     
|Northern Border Pipeline                                                                                                                                                                                                                                                                                                                                                             |  | 50            | % |  | $                      | 418,982 |     |      | $ | 437,518 |     |  | 
|Bighorn Gas Gathering                                                                                                                                                                                                                                                                                                                                                                |  | 49            | % |  |                        | 97,716  |     |      |   | 98,299  |     |  | 
|Fort Union Gas Gathering                                                                                                                                                                                                                                                                                                                                                             |  | 37            | % |  |                        | 85,197  |     |      |   | 82,220  |     |  | 
|Lost Creek Gathering Company (a)                                                                                                                                                                                                                                                                                                                                                     |  | 35            | % |  |                        | 75,612  |     |      |   | 74,151  |     |  | 
|Other                                                                                                                                                                                                                                                                                                                                                                                |  | Various       |   |  |                        | 78,753  |     |      |   | 56,691  |     |  | 
|Investments in unconsolidated affiliates                                                                                                                                                                                                                                                                                                                                             |  |               |   |  | $                      | 756,260 | (b) |      | $ | 748,879 | (b) |  | 
|                                                                                                                                                                                                                                                                                                                                                                                    
|(a) -   We are entitled to receive an incentive allocation of earnings from
third-party gathering services revenue recognized by Lost Creek Gathering Company. As a result of the incentive, our share of Lost Creek Gathering Company's income exceeds its 35 percent ownership interest. (b) -   Equity method goodwill (Note D) was $185.6 million at December 31, 2007 and
2006.

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for
the periods indicated.



|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                          |        |      |   |        |  |   |        |  | 
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | ------ | ---- | - | ------ |  | - | ------ |  | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | Years Ended December 31, |        |     
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | 2007                     |        | 2006 |   | 2005   |  |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | (Thousands of dollars)   |        |     
|Northern Border Pipeline (a)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | $                        | 62,008 |      | $ | 72,393 |  | $ | -      |  | 
|Bighorn Gas Gathering                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  |                          | 7,416  |      |   | 8,223  |  |   | 9,411  |  | 
|Fort Union Gas Gathering                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |                          | 9,681  |      |   | 9,030  |  |   | 6,747  |  | 
|Lost Creek Gathering Company                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |  |                          | 4,790  |      |   | 5,363  |  |   | 6,315  |  | 
|Guardian Pipeline (b)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  |                          | -      |      |   | -      |  |   | 2,263  |  | 
|Other                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  |                          | 6,013  |      |   | 874    |  |   | -      |  | 
|Equity earnings from investments                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | $                        | 89,908 |      | $ | 95,883 |  | $ | 24,736 |  | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(a) -   Beginning January 1, 2006, our interest in Northern Border Pipeline
is accounted for as an investment under the equity method (Note B). For the first three months of 2006, we included 70 percent of Northern Border Pipelines income in equity earnings from investments. After the sale of a 20 percent interest in
Northern Border Pipeline in April 2006, we included 50 percent of Northern Border Pipeline's income in equity earnings from investments. (b) -   In April 2006, we acquired the 66-2/3percent interest in Guardian
Pipeline not previously owned by us, increasing our ownership to 100 percent. Following the completion of the transactions, we consolidated Guardian Pipeline retroactive to January 1, 2006 (Note B).



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Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated
affiliates is presented below.



|                                              |  |                        |           |   |      |   |           |  | 
|--------------------------------------------- |  | ---------------------- | --------- | - | ---- | - | --------- |  | 
|                                              |  | December 31,           |           |  
|                                              |  | 2007                   |           |   | 2006 |   |          
|                                              |  | (Thousands of dollars) |           |  
|Balance Sheet                                 |  |                        |           |   |      |   |           |  | 
|Current assets                                |  | $                      | 102,805   |   |      | $ | 76,376    |  | 
|Property, plant and equipment, net            |  |                        | 1,724,330 |   |      |   | 1,678,099 |  | 
|Other noncurrent assets                       |  |                        | 25,882    |   |      |   | 24,109    |  | 
|Current liabilities                           |  |                        | 79,593    |   |      |   | 240,358   |  | 
|Long-term debt                                |  |                        | 717,301   |   |      |   | 492,017   |  | 
|Other noncurrent liabilities                  |  |                        | 10,278    |   |      |   | 2,494     |  | 
|Accumulated other comprehensive income (loss) |  |                        | (2,441    | ) |      |   | 978       |  | 
|Owners equity                                |  |                        | 1,048,286 |   |      |   | 1,042,737 |  | 



|                         |  |                          |         |      |   |         |  |   |         |  | 
|------------------------ |  | ------------------------ | ------- | ---- | - | ------- |  | - | ------- |  | 
|                         |  | Years Ended December 31, |         |     
|                         |  | 2007                     |         | 2006 |   | 2005    |  |  
|                         |  | (Thousands of dollars)   |         |     
|Income Statement         |  |                          |         |      |   |         |  |   |         |  | 
|Operating revenue        |  | $                        | 404,399 |      | $ | 386,448 |  | $ | 101,390 |  | 
|Operating expenses       |  |                          | 172,997 |      |   | 159,452 |  |   | 34,470  |  | 
|Net income               |  |                          | 184,434 |      |   | 183,732 |  |   | 49,742  |  | 
|                         |  |                          |         |     
|Distributions paid to us |  | $                        | 103,785 |      | $ | 123,427 |  | $ | 16,440  |  | 



|L. | NET INCOME PER UNIT
|-- | -------------------

Net income per unit is computed by dividing
net income, after deducting the general partners allocation, by the weighted average number of outstanding limited partner units. The general partner owns a 2 percent interest in us and also owns incentive distribution rights that provide for
an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels. For purposes of our calculation of net income per unit, net income is generally allocated to the
general partner as follows: (1) an amount based upon the 2 percent general partner interest in net income, and (2) the amount of the general partners incentive distribution rights based on the total cash distributions declared for
the period. The amount of incentive distributions allocated to our general partners totaled $50.6 million, $31.6 million and $8.0 million for 2007, 2006 and 2005, respectively. The distribution paid to our general partner shown on the accompanying
Consolidated Statements of Changes in Partners Equity and Comprehensive Income of $54.7 million in 2007, $28.4 million in 2006 and $11.2 million in 2005, included incentive distributions paid to the general partners in 2007, 2006 and 2005 of
approximately $47.1 million, $23.1 million and $8.0 million, respectively. Gains resulting from interim capital transactions, as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement
provides that if such distributions were made, the incentive distribution rights would not apply. Accordingly, the gain on sale of assets for 2007 and 2006 had no impact on the incentive distribution rights.

As discussed in Note B, we completed the ONEOK Transactions during the second quarter of 2006; however, for accounting purposes, the transactions were accounted for
retroactive to January 1, 2006. Net income from the ONEOK Energy Assets prior to the April 2006 acquisition was approximately $35.8 million and has been reflected in our earnings for 2006. For purposes of our calculation of 2006 income per
unit, these pre-acquisition earnings were allocated to the general partner, as they retained the related cash flow for that period.

The following
summarizes our quarterly cash distribution activity for 2007:

| |  |  | In January 2007, we declared a cash distribution of $0.98 per unit for the fourth quarter of 2006. The distribution was paid on February 14, 2007, to
unitholders of record on January 31, 2007.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In April 2007, we declared a cash distribution of $0.99 per unit for the first quarter of 2007. The distribution was paid on May 14, 2007, to unitholders of
record as of April 30, 2007.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In July 2007, we declared a cash distribution of $1.00 per unit for the second quarter of 2007. The distribution was paid on August 14, 2007, to unitholders of
record on July 31, 2007.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | In October 2007, we declared a cash distribution of $1.01 per unit for the third quarter of 2007. The distribution was paid on November 14, 2007, to
unitholders of record on October 31, 2007.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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On January 15, 2008, we declared a cash distribution of $1.025 per unit ($4.10 per unit on an annualized basis) for
the fourth quarter of 2007. The distribution was paid on February 14, 2008, to unitholders of record on January 31, 2008.



|M. | RELATED-PARTY TRANSACTIONS
|-- | --------------------------

Intersegment and affiliate sales are
recorded on the same basis as sales to unaffiliated customers. Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segments revenues are from ONEOK and its
subsidiaries, which utilize both transportation and storage services.

As part of the ONEOK Transactions, we acquired certain contractual rights to the
Bushton Plant that is leased by OBPI. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services at the Bushton Plant through 2012. We have contracted for all of the capacity of the Bushton Plant
from OBPI. In exchange, we pay OBPI for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of OBPIs obligations under equipment leases covering the Bushton Plant.

In April 2006, we entered into a Services Agreement with ONEOK, ONEOK Partners GP and NBP Services (the Services Agreement) that replaced the Administrative Services
Agreement between us and NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the
Services Agreement, ONEOK will provide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP continues to operate
our interstate natural gas pipeline assets according to each pipelines operating agreement, except for the operating agreement between ONEOK Partners GP and Northern Border Pipeline, which terminated effective April 1, 2007. ONEOK
Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its responsibilities.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financing services, employee
benefits provided through ONEOKs benefit plans, administrative services, insurance and office space leased in ONEOKs headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our
affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all
employees is allocated based upon the number of employees. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that
include gross plant and investment, operating income and wages. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

An affiliate of ONEOK enters into some of the commodity derivative contracts at the direction of and on behalf of our Natural Gas Gathering and Processing segment. See Note C for a discussion of our derivative
instruments and hedging activities.

The following table sets forth the transactions with related parties for the periods
indicated.



|                                    |  |                          |         |      |   |         |  |   |        |  | 
|----------------------------------- |  | ------------------------ | ------- | ---- | - | ------- |  | - | ------ |  | 
|                                    |  | Years Ended December 31, |         |     
|                                    |  | 2007                     |         | 2006 |   | 2005    |  |  
|                                    |  | (Thousands of dollars)   |         |     
|Revenues                            |  | $                        | 626,764 |      | $ | 595,702 |  | $ | 7,683  |  | 
|                                   
|Expenses                            |  |                          |         |      |   |         |  |   |        |  | 
|Administrative and general expenses |  | $                        | 171,741 |      | $ | 175,270 |  | $ | 52,579 |  | 
|Interest expense                    |  |                          | -       |      |   | 21,372  |  |   | -      |  | 
|Total expenses                      |  | $                        | 171,741 |      | $ | 196,642 |  | $ | 52,579 |  | 
|                                   



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|N. | QUARTERLY FINANCIAL DATA (UNAUDITED)
|-- | ------------------------------------



|                             |  |                                                 |           |               |   |              |  |               |           |  |   |           |  | 
|---------------------------- |  | ----------------------------------------------- | --------- | ------------- | - | ------------ |  | ------------- | --------- |  | - | --------- |  | 
|Year Ended December 31, 2007 |  | FirstQuarter                                    |           | SecondQuarter |   | ThirdQuarter |  | FourthQuarter |           | 
|                             |  | (Thousands of dollars, except per unit amounts) |           |              
|Total revenues               |  | $                                               | 1,168,674 |               | $ | 1,375,314    |  | $             | 1,410,257 |  | $ | 1,877,313 |  | 
|Net margin                   |  | $                                               | 205,370   |               | $ | 217,570      |  | $             | 213,884   |  | $ | 259,069   |  | 
|Operating income             |  | $                                               | 104,376   |               | $ | 107,558      |  | $             | 105,116   |  | $ | 129,733   |  | 
|Net income                   |  | $                                               | 95,756    |               | $ | 94,619       |  | $             | 95,916    |  | $ | 121,456   |  | 
|Net income per unit          |  | $                                               | 1.00      |               | $ | 0.97         |  | $             | 0.98      |  | $ | 1.27      |  | 
|                             |  |                                                 |           |               |  
|Year Ended December 31, 2006 |  | FirstQuarter                                    |           | SecondQuarter |   | ThirdQuarter |  | FourthQuarter |           | 
|                             |  | (Thousands of dollars, except per unit amounts) |           |              
|Total revenues               |  | $                                               | 1,179,613 |               | $ | 1,163,859    |  | $             | 1,218,541 |  | $ | 1,176,235 |  | 
|Net margin                   |  | $                                               | 202,062   |               | $ | 213,111      |  | $             | 211,466   |  | $ | 216,909   |  | 
|Operating income             |  | $                                               | 100,174   |               | $ | 212,779      |  | $             | 107,673   |  | $ | 90,586    |  | 
|Net income                   |  | $                                               | 70,504    |               | $ | 196,199      |  | $             | 98,222    |  | $ | 80,261    |  | 
|Net income per unit          |  | $                                               | 0.67      |               | $ | 2.22         |  | $             | 1.04      |  | $ | 0.82      |  | 

Total revenues and net margin for the first and second quarters in the tables above were restated to be consistent
with the classification used in our September 30, 2007 Quarterly Report on Form 10-Q and in this Annual Report on Form 10-K. The change was not material.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that
we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SECs rules and forms. Under the supervision and with the participation of senior management, including the Chief
Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, we evaluated our disclosure controls and procedures, as such term is
defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer concluded that our disclosure controls and procedures were effective as of
December 31, 2007, to ensure the timely disclosure of required information in our periodic SEC filings.

Managements Report on Internal
Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as
such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal
control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Our internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in their report that is included herein (Item 8).



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Changes in Internal Controls Over Financial Reporting

We have made no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the year ended
December 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Partnership Board of Directors and Audit Committee

We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP, which consists of six members designated
by ONEOK, the parent corporation of our general partner. We refer to the Board of Directors of ONEOK Partners GP as our Board of Directors. Because we are a limited partnership and meet the definition of a controlled company under the
listing standards of the NYSE, certain listing standards of the NYSE are not applicable to us. Accordingly, Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner be comprised
of a majority of independent directors, and Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner maintain a nominating committee and a compensation committee, each
consisting entirely of independent directors, are not applicable to us. However, our Board of Directors has affirmatively determined that three members of our Board of Directors, Gary N. Petersen, Gerald B. Smith and Gil J. Van Lunsen, have no
material relationship with us and are independent under our Governance Guidelines and the listing standards of the NYSE.

Our Board of
Directors has appointed an Audit Committee consisting of the three members of our Board of Directors who are independent under our Governance Guidelines and the listing standards of the NYSE. The Audit Committee has oversight responsibility with
respect to the integrity of our financial statements, the performance of our internal audit function, the independent auditors qualification and independence and our compliance with legal and regulatory requirements. The Audit Committee
directly appoints, retains, evaluates and may terminate our independent auditor. The Audit Committee reviews our annual and quarterly financial statements. The Audit Committee also has the authority to review specific matters that may present a
conflict of interest in order to determine if the resolution of such conflict proposed by our Board of Directors is fair and reasonable to our unitholders and to engage advisors to assist it in carrying out its duties. The Audit Committee has all
other responsibilities required by the applicable NYSE listing standards and applicable SEC rules. The Board of Directors of our general partner has adopted a written charter for our Audit Committee.

The members of our Board of Directors and Audit Committee are not elected by unitholders. Accordingly, we do not have a procedure by which security holders may recommend
nominees to our Board of Directors or Audit Committee. The persons designated as our executive officers serve in that capacity at the discretion of our Board of Directors.



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Directors and Executive Officers

The following table sets forth the members of the Board of Directors and Audit Committee and the executive officers of our general partner. There are no family relationships between any of our executive officers or
members of the Board of Directors and the Audit Committee. Some of these individuals are also officers of certain of our subsidiaries or affiliates.



|                  |  |     |  |                                                             
|----------------- |  | --- |  | ------------------------------------------------------------
|Name              |  | Age |  | Position                                                    
|John W. Gibson    |  | 55  |  | Chairman of the Board, President and Chief Executive Officer
|                  |  |    
|James C. Kneale   |  | 56  |  | President and Chief Operating Officer, ONEOK, Inc.          
|                  |  |     |  | Member, Board of Directors                                  
|                  |  |    
|Curtis L. Dinan   |  | 40  |  | Senior Vice President, Chief Financial Officer and Treasurer
|                  |  |     |  | Member, Board of Directors                                  
|                  |  |    
|John R. Barker    |  | 60  |  | Executive Vice President, General Counsel and Secretary     
|                  |  |    
|Caron A. Lawhorn  |  | 46  |  | Senior Vice President and Chief Accounting Officer          
|                  |  |    
|Gary N. Petersen  |  | 57  |  | Member, Board of Directors and Audit Committee              
|                  |  |    
|Gerald B. Smith   |  | 57  |  | Member, Board of Directors and Chairman, Audit              
|                  |  |     |  | Committee                                                   
|                  |  |    
|Gil J. Van Lunsen |  | 65  |  | Member, Board of Directors and Audit Committee              

John W. Gibson became our president and chief executive officer effective January 1, 2007, and chairman of
our Board of Directors on October 16, 2007. He served as our president and chief operating officer from May through December 2006. From 2005 until May 2006, he was president of ONEOK Energy companies, which included ONEOKs gathering and
processing, natural gas liquids, pipelines and storage and energy services business segments, some of which were acquired by us in April 2006. Prior to that, he was president, Energy, from 2000 to 2005 for ONEOK.

James C. Kneale became the president and chief operating officer of ONEOK effective January 1, 2007. He served as our executive vice president and chief financial
officer from May through December 2006. From 1999 to 2000, he was vice president, treasurer and chief financial officer and from 2001 to 2004, senior vice president, treasurer and chief financial officer for ONEOK. From 2005 through May 2006, he was
executive vice president, finance and administration and chief financial officer for ONEOK.

Curtis L. Dinan became our senior vice president, chief
financial officer and treasurer effective January 1, 2007. He was elected to our Board of Directors on October 16, 2007. Mr. Dinan is a member of both the Management and Audit Committees of Northern Border Pipeline. Mr. Dinan is
also the Senior Vice President, Chief Financial Officer and Treasurer of ONEOK. Mr. Dinan served as senior vice president and chief accounting officer of ONEOK from August 2004 through December 2006 and served as vice president and chief
accounting officer of ONEOK from February 2004 to August 2004. Prior to joining ONEOK in February 2004, Mr. Dinan served as an assurance and business advisory partner at Grant Thornton, LLP from 2002 to 2004.

John R. Barker became our executive vice president, general counsel and secretary in May 2006. Mr. Barker is also senior vice president, general counsel and
assistant secretary for ONEOK, having been appointed to that position in 2004. From 1994 to 2004, he was a stockholder, president and director of Gable & Gotwals, a law firm located in Tulsa, Oklahoma, which provides legal services to both
us and ONEOK.

Caron A. Lawhorn was named senior vice president and chief accounting officer on January 15, 2008. Ms. Lawhorn is Chair of the
Audit Committee of Northern Border Pipeline. Ms. Lawhorn has served as senior vice president and chief accounting officer for ONEOK since January 1, 2007, and will continue to serve in this capacity. Prior to her current position,
Ms. Lawhorn served ONEOK as senior vice president of financial services and treasurer from January 2005 to January 2007, vice president and controller from August 2004 to January 2005, vice president of audit and risk control from May 2003 to
August 2004, and manager of audit services from September 1998 to May 2003.



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Gary N. Petersen was appointed to the Audit Committee in 2002. Since 1998, he has provided consulting services related to
strategic and financial planning. Additionally, he is president of Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant Energy-Minnegasco. He served as president and chief operating officer of Reliant Energy-Minnegasco
from 1991 to 1998. Prior to his employment at Minnegasco, he was a senior auditor with Arthur Andersen. He currently serves on the boards of the YMCA of Metropolitan Minneapolis and the Dunwoody College of Technology.

Gerald B. Smith was appointed to the Audit Committee in 1994. He is chairman and chief executive officer and co-founder of Smith, Graham & Company
Investment Advisors, a global investment management firm, which was founded in 1990. He is a member of the board of trustees of the Charles Schwab Family of Funds and lead independent director and member of the Cooper Industries audit
committee. He is a former director of the Fund Management Board of Robeco Group, Rorento N.V. (Netherlands).

Gil J. Van Lunsen was appointed to the
Audit Committee in March 2005. Prior to his retirement in 2000, Mr. Van Lunsen was a managing partner of KPMG LLP at the firms Tulsa, Oklahoma office. He began his career with KPMG LLP in 1968. He is currently a director
and audit committee chairman of Array Biopharma in Boulder, Colorado.

Director Compensation

Compensation for our non-management directors for the year ended December 31, 2007, consisted of an annual cash retainer of $65,000 and meeting fees of $1,000 for
each Audit Committee meeting attended in person or $500 for each Audit Committee meeting attended by telephone. In addition, the chair of our Audit Committee received an additional annual cash fee of $10,000 and each other member of the Audit
Committee received an additional cash fee of $5,000. Non-management directors are reimbursed for their expenses related to their attendance at Board of Director and Audit Committee meetings. A director who is also an officer or employee of ONEOK
Partners GP or ONEOK receives no compensation for his or her service as a director.

We are required to indemnify the members of the Board of Directors and
the general partner, its affiliates and its respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a
manner reasonably believed to be in, or (in the case of a person other than the general partner) not opposed to, our best interests and, with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful.

The following table sets forth the compensation paid to our non-management directors in 2007.

2007 DIRECTOR COMPENSATION



|                  |  |                             |  |                |  |                 |  |                                         |  |                                                                      |  |                          |  |          |  | 
|----------------- |  | --------------------------- |  | -------------- |  | --------------- |  | --------------------------------------- |  | -------------------------------------------------------------------- |  | ------------------------ |  | -------- |  | 
|Name              |  | FeesEarned orPaid inCash($) |  | StockAwards($) |  | OptionAwards($) |  | Non EquityIncentive PlanCompensation($) |  | Change inPension ValueandNonqualifiedDeferredCompensationEarnings($) |  | All OtherCompensation($) |  | Total($) |  | 
|Gary N. Petersen  |  | 77,000                      |  |               |  |                |  |                                        |  |                                                                     |  |                         |  | 77,000   |  | 
|Gerald B. Smith   |  | 82,000                      |  |               |  |                |  |                                        |  |                                                                     |  |                         |  | 82,000   |  | 
|Gil J. Van Lunsen |  | 77,000                      |  |               |  |                |  |                                        |  |                                                                     |  |                         |  | 77,000   |  | 

Compensation Committee Interlocks and Insider Participation

We do not have a compensation committee. During 2007, the compensation of our named executive officers was determined by ONEOKs Executive Compensation Committee,
which consists of independent members of the ONEOK Board of Directors. No member of ONEOKs Executive Compensation Committee is, or was formerly, an officer, director or employee of ONEOK Partners or any if its subsidiaries.



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Governance Matters

Audit Committee Independence - Our Board of Directors has appointed a standing Audit Committee. Our guidelines for determining the independence of members of the Audit Committee are included in our Governance Guidelines and provide
that members of the Audit Committee shall at all times qualify as independent under the listing standards of the NYSE and the applicable rules of the SEC and other applicable laws. At least annually, the Board of Directors reviews the relationships
of each Audit Committee member with us to affirmatively determine the independence of each member. In February 2008, our Board of Directors affirmatively determined that Mr. Petersen, Mr. Smith, and Mr. Van Lunsen meet the standards
for independence set forth in the Governance Guidelines and are therefore independent.

Audit Committee Financial Experts - Our Board of Directors
annually reviews the financial expertise of the members of our Audit Committee. In February 2008, our Board of Directors determined that Mr. Petersen, Mr. Smith, and Mr. Van Lunsen are each audit committee financial
experts, as defined by the rules of the SEC.

Executive Sessions of Board and Audit Committee - Our Board of Directors has documented its
governance practices in our Governance Guidelines. The Board of Directors of our general partner holds regular executive sessions in which non-management board members meet without any members of management present. The chairman of our Audit
Committee, Mr. Smith, presides at regular sessions of the non-management members of our Board of Directors. Meetings of the non-management board and committee members are scheduled in connection with each in person meeting of our Board of
Directors and Audit Committee.

Service on Other Audit Committees - Mr. Smith serves on the audit committee of one other public company.
Mr. Van Lunsen serves on the audit committee of one other public company. The Board of Directors has determined that Mr. Smith and Mr. Van Lunsens service on these other audit committees does not impair their ability to
effectively serve on our Audit Committee.

Section 16(a) Beneficial Ownership Reporting Compliance - Section 16(a) of the Exchange Act requires
executive officers, members of the Board of Directors and persons who own more than 10 percent of our common units to file reports of ownership and changes in ownership with the SEC and the NYSE and to furnish us with copies of all
Section 16(a) forms they file. Based solely on our review of the copies of such forms received by us during and with respect to the 2007 fiscal year, or written representations from certain reporting persons that no Form 5s were required for
those persons, we believe that during 2007 our reporting persons complied with all applicable filing requirements in a timely manner.

Governance
Guidelines - The Board of Directors of our general partner has adopted Governance Guidelines that address several governance matters, including responsibilities of directors, the composition and responsibility of the Audit Committee, the conduct
and frequency of board meetings, management succession, director access to management and outside advisors, director orientation and continuing education, and annual self-evaluation of the board. The Board of Directors of our general partner
recognizes that effective governance is an on-going process, and thus, the Board of Directors will review our Governance Guidelines periodically as deemed necessary.

Code of Ethics - The Board of Directors of our general partner has adopted an Accounting and Financial Reporting Code of Ethics applicable to our chief executive officer, chief financial officer and chief
accounting officer. In addition to other matters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with
applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code. We intend to promptly post on our website any amendment to, or waiver
from, any provision of our Accounting and Financial Reporting Code of Ethics in accordance with the applicable rules of the SEC and NYSE.

Code of
Conduct - The Board of Directors of our general partner has adopted a Code of Business Conduct applicable to the members of our Board of Directors and Audit Committee, our officers and the employees of ONEOK, ONEOK Partners GP, and ONEOK
Services Company, who provide services to us. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance
policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code. We intend to promptly post on our website any amendments to, or waivers from (including any implicit waiver), any
provision of our Code of Business Conduct in accordance with the applicable rules of the SEC and NYSE.



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Web Access - We provide access through our website at www.oneokpartners.comto current information relating
to our governance, including our Audit Committee Charter, our Accounting and Financial Reporting Code of Ethics, our Code of Business Conduct, our Governance Guidelines and other matters impacting our governance principles. You may copy each of
these documents from our website. You may also contact the office of the secretary of ONEOK Partners GP for printed copies of these documents free of charge.

Communications with Directors - Our Board of Directors believes that it is managements role to speak for us. Our Board of Directors also believes that any communications between members of the Board of Directors and interested
parties, including unitholders, should be conducted with the knowledge of our chairman, president and chief executive officer. Interested parties, including unitholders, may contact one or more members of our Board of Directors, including
non-management directors and non-management directors as a group, by writing to the director or directors in care of our corporate secretary at our principal executive offices. A communication received from an interested party or unitholder will be
promptly forwarded to the director or directors to whom the communication is addressed. A copy of the communication will also be provided to our president and chief executive officer. We will not, however, forward sales or marketing materials or
correspondence primarily commercial in nature or not clearly identified as interested party or unitholder correspondence.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, ONEOK Partners GP, the
executive officers of which are employees of ONEOK. Certain officers of ONEOK Partners GP are deemed to be executive officers of us. We reimburse ONEOK for a portion of the total compensation paid to the executive officers of our general partner as
provided by our Services Agreement with ONEOK. Please read Certain Relationships and Related Party Transactions, and Director Independence - Services Agreement for a description of the Services Agreement.

We do not have a compensation committee. The compensation of the officers of our general partner, who are deemed to be our officers, is set by the Executive Compensation
Committee of the Board of Directors of ONEOK. A discussion of the objectives of, and other matters related to, ONEOKs compensation programs is included in ONEOKs compensation discussion and analysis and other disclosure related to ONEOK
executive compensation contained in ONEOKs 2008 Proxy Statement as filed with the SEC (ONEOK 2008 Proxy Statement), a copy of which is provided on, and may be copied from, ONEOKs website at www.oneok.com and is available free of
charge from the secretary of ONEOK Partners GP upon request.

Under our Services Agreement with ONEOK, a portion of the compensation expense for our named
executive officers is allocated by ONEOK to us. The compensation amounts shown in the following table represent that portion of the named executive officers total compensation which is allocated to and paid by us under the Services Agreement.



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The following table summarizes the compensation allocated to and paid by us in 2007 for our principal executive officer,
principal financial officer and the three other most highly compensated executive officers of our general partner, ONEOK Partners GP, which we collectively refer to as the named executive officers.

Summary Compensation Table For 2007



|                                                                 |  |      |  |           |         |                    |   |                     |  |                                            |         |                                                                         |   |                             |  |           |           |  |   |        |  |   |          
|---------------------------------------------------------------- |  | ---- |  | --------- | ------- | ------------------ | - | ------------------- |  | ------------------------------------------ | ------- | ----------------------------------------------------------------------- | - | --------------------------- |  | --------- | --------- |  | - | ------ |  | - | ---------
|Name and Principal Position                                      |  | Year |  | Salary($) |         | Stock Awards($)(1) |   | Option Awards($)(2) |  | Non-EquityIncentive PlanCompensation($)(3) |         | Change inPension ValueandNonqualifiedDeferredCompensationEarnings($)(4) |   | All OtherCompensation($)(5) |  | Total ($)
|David L. Kyle                                                    |  | 2007 |  | $         | 405,705 |                    | $ | 1,532,891           |  | $                                          | -       |                                                                         | $ | -                           |  | $         | 1,096,862 |  | $ | 79,523 |  | $ | 3,114,981
|Chairman and Chief Executive Officer (6)                         |  | 2006 |  | $         | 307,043 |                    | $ | 1,984,503           |  | $                                          | 4,987   |                                                                         | $ | 690,846                     |  | $         | 444,716   |  | $ | 54,932 |  | $ | 3,487,027
|John W. Gibson                                                   |  | 2007 |  | $         | 295,926 |                    | $ | 930,262             |  | $                                          | -       |                                                                         | $ | 536,963                     |  | $         | 560,163   |  | $ | 67,930 |  | $ | 2,391,244
|Chairman, President and Chief Executive Officer (6)              |  | 2006 |  | $         | 326,250 |                    | $ | 794,237             |  | $                                          | 2,210   |                                                                         | $ | 491,250                     |  | $         | 377,996   |  | $ | 43,448 |  | $ | 2,035,391
|James C. Kneale                                                  |  | 2007 |  | $         | 248,196 |                    | $ | 849,464             |  | $                                          | 64,309  |                                                                         | $ | 389,000                     |  | $         | 489,172   |  | $ | 33,201 |  | $ | 2,073,342
|President and Chief Operating Officer, ONEOK, Inc.               |  | 2006 |  | $         | 158,014 |                    | $ | 441,904             |  | $                                          | 173,629 |                                                                         | $ | 227,032                     |  | $         | 185,975   |  | $ | 21,875 |  | $ | 1,208,429
|Curtis L. Dinan                                                  |  | 2007 |  | $         | 143,190 |                    | $ | 122,707             |  | $                                          | -       |                                                                         | $ | 181,374                     |  | $         | 45,738    |  | $ | 13,667 |  | $ | 506,676  
|Senior Vice President, Chief Financial Officer and Treasurer (6) |  | 2006 |  | $         | 82,472  |                    | $ | 102,515             |  | $                                          | -       |                                                                         | $ | 59,165                      |  | $         | 21,727    |  | $ | 8,475  |  | $ | 274,354  
|Pierce H. Norton II                                              |  | 2007 |  | $         | 261,354 |                    | $ | 199,306             |  | $                                          | -       |                                                                         | $ | 320,000                     |  | $         | 37,175    |  | $ | 14,233 |  | $ | 832,068  
|Executive Vice President - Natural Gas                           |  | 2006 |  | $         | 225,000 |                    | $ | 165,200             |  | $                                          | -       |                                                                         | $ | 215,000                     |  | $         | 32,769    |  | $ | 13,683 |  | $ | 651,652  



|(1) | The amounts included in the table reflect the expense allocated to and recognized by us for restricted stock, restricted stock incentive units and performance units granted under
the ONEOK Long-Term Incentive Plan (LTI Plan) and the ONEOK Equity Compensation Plan, the grant date fair value of which was determined in accordance with Financial Accounting Standards No. 123 (revised 2004), Share-Based Payments,
(Statement 123R). Assumptions used in the calculation of the value of these equity grants are included in Note O to the ONEOK audited financial statements for the year ended December 31, 2007, included in the ONEOK 2007 Annual Report on Form
10-K filed with the SEC on February 27, 2008.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Annual grants of restricted stock and restricted stock incentive units
vest three years from the date of grant. Because no shares of ONEOK common stock are issued under a restricted stock incentive unit until the unit vests, no dividends are payable with respect to restricted stock incentive units. Performance units do
not pay dividends and vest three years from the date of grant at which time the holder is entitled to receive a percentage (0 percent to 200 percent in increments of 50 percent) of the performance units granted based on ONEOKs total
shareholder return over the three-year performance cycle compared to the total shareholder return of a peer group of energy companies. Grants of restricted stock, restricted stock incentive units and performance units made in 2003 and grants of
restricted stock incentive units and performance units made in 2006 and 2007 are payable in shares of ONEOK common stock upon vesting. Grants of restricted stock incentive units and performance units made in 2004 and 2005 are payable one-third in
cash and two-thirds in shares upon vesting. The fair value of restricted stock and restricted stock incentive units for the purposes of Statement 123R was determined on the date of grant based on the closing stock price of ONEOK common stock on the
grant date, adjusted for the current dividend yield. The grant date fair value of the performance units granted in 2003, 2004 and 2005 for the purposes of Statement 123R was determined on the date of grant based on the closing stock price of ONEOK
common stock on the grant date, adjusted for the current dividend yield. With respect to the performance units granted in 2006 and 2007, the grant date fair value for the purposes of Statement 123R was determined using a valuation model that
considers the market condition (total shareholder return), using assumptions developed from historical information of ONEOK and the referenced peer group.



|(2) | No options were granted by ONEOK in 2007. However, the remaining unamortized expense from restored options granted in 2006 was fully recognized as of May 2007. No options were
granted in 2006, except for restored options granted in connection with the exercise of options granted under the LTI Plan. Effective January 1, 2007, the restorative feature of all outstanding ONEOK stock options was eliminated. The 2003
option grant vested on February 20, 2006. The amounts included in the table reflect our allocated portion of the grant date fair value of the 2003 grant and the restored options granted in 2006 as expensed in accordance with Statement 123R.
Assumptions used in the calculation of the value of option grants are included in Note O to the ONEOK audited financial statements for the year ended December 31, 2007, included in the ONEOK 2007 Annual Report on Form 10-K filed with the SEC on
February 27, 2008.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | Reflects the amounts allocated to and paid by us under the ONEOK annual officer incentive plan. The plan provides that ONEOK officers may receive annual cash incentive awards based
on the performance and profitability of ONEOK, the performance of particular business units of ONEOK, and individual performance. The corporate and business unit criteria and individual performance criteria are established annually by the ONEOK
Executive Compensation Committee of the ONEOK Board of Directors. The Committee also establishes annual target awards for each ONEOK officer. For a discussion of the performance criteria established by the ONEOK Executive Compensation Committee for
awards under the 2007 annual officer incentive plan, see Components of Compensation - Annual Cash Compensation in the ONEOK 2008 Proxy Statement.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|(4) | Reflects the portion of the aggregate current year change in pension values and above market earnings on nonqualified deferred compensation allocated to us for each named executive
officer. The change in pension values is based on the change of the present value of the benefit. For a discussion of the ONEOK pension plan, see the ONEOK 2008 Proxy Statement. The present value is based on the earliest age for which
an unreduced benefit is available (age 62) and assumptions from the September 30, 2007 and 2006 measurement dates for the ONEOK pension plan.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Our allocated portion of above market earnings on nonqualified deferred compensation for 2006 and 2007 were $671 and $0, respectively, for Mr. Kyle and $394 and $765, respectively, for Mr. Kneale. No
other named executive officers received above market earnings. For additional information on the ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, see Long-Term Compensation Plans - Nonqualified Deferred Compensation
Plan in the ONEOK 2008 Proxy Statement.



|(5) | Reflects the portion allocated to us of the amounts paid as ONEOKs dollar for dollar match of contributions made by the named executive officer under the ONEOK, Inc. Employee
Nonqualified Deferred Compensation Plan, amounts paid as ONEOKs dollar for dollar match of contributions made by the named executive officer under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; amounts paid for country club
membership; amounts paid as tax reimbursements for employee stock awards under the ONEOK, Inc. Employee Stock Award Program; amounts expensed in accordance with Statement 123R for shares issued under the ONEOK, Inc. Employee Stock Award Program; and
amounts paid as employee service awards, as follows:
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                    |  |      |  |                                                     |        |                           |   |                       |  |              |        |  |                       |     |                  |  |   |     |  |   |     |  | 
|------------------- |  | ---- |  | --------------------------------------------------- | ------ | ------------------------- | - | --------------------- |  | ------------ | ------ |  | --------------------- | --- | ---------------- |  | - | --- |  | - | --- |  | 
|Name                |  | Year |  | Match UnderNonqualifiedDeferredCompensationPlan (a) |        | Match UnderThrift Plan(b) |   | CountryClubMembership |  | ServiceAward |        |  | EmployeeStockAward(c) |     | TaxReimbursement |  |  
|David L. Kyle       |  | 2007 |  | $                                                   | 72,669 |                           | $ | 6,444                 |  | $            | -      |  | $                     | -   |                  |  | $ | 238 |  | $ | 172 |  | 
|                    |  | 2006 |  | $                                                   | 49,936 |                           | $ | 4,768                 |  | $            | -      |  | $                     | -   |                  |  | $ | 130 |  | $ | 98  |  | 
|                    |  |      |  |                                                     |        |                           |   |                      
|John W. Gibson      |  | 2007 |  | $                                                   | 30,070 |                           | $ | 6,444                 |  | $            | 31,006 |  | $                     | -   |                  |  | $ | 238 |  | $ | 172 |  | 
|                    |  | 2006 |  | $                                                   | 33,075 |                           | $ | 9,900                 |  | $            | -      |  | $                     | -   |                  |  | $ | 270 |  | $ | 203 |  | 
|                    |  |      |  |                                                     |        |                           |   |                      
|James C. Kneale     |  | 2007 |  | $                                                   | 26,347 |                           | $ | 6,444                 |  | $            | -      |  | $                     | -   |                  |  | $ | 238 |  | $ | 172 |  | 
|                    |  | 2006 |  | $                                                   | 16,455 |                           | $ | 4,795                 |  | $            | -      |  | $                     | 396 | (d)              |  | $ | 131 |  | $ | 98  |  | 
|                    |  |      |  |                                                     |        |                           |   |                      
|Curtis L. Dinan     |  | 2007 |  | $                                                   | 6,873  |                           | $ | 6,444                 |  | $            | -      |  | $                     | -   |                  |  | $ | 238 |  | $ | 112 |  | 
|                    |  | 2006 |  | $                                                   | 3,550  |                           | $ | 4,733                 |  | $            | -      |  | $                     | -   |                  |  | $ | 129 |  | $ | 63  |  | 
|                    |  |      |  |                                                     |        |                           |   |                      
|Pierce H. Norton II |  | 2007 |  | $                                                   | -      |                           | $ | 13,500                |  | $            | -      |  | $                     | -   |                  |  | $ | 498 |  | $ | 235 |  | 
|                    |  | 2006 |  | $                                                   | -      |                           | $ | 13,200                |  | $            | -      |  | $                     | -   |                  |  | $ | 361 |  | $ | 122 |  | 

(a) For additional information on the ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan,
see Long-Term Compensation Plans - Nonqualified Deferred Compensation Plan in the ONEOK 2008 Proxy.

(b) The Thrift Plan for
Employees of ONEOK, Inc. and Subsidiaries is a tax qualified plan which covers all ONEOK employees. Employee contributions are discretionary. Subject to certain limits, ONEOK matches 100 percent of employee contributions to the plan up to a maximum
of 6 percent.

(c) Under the ONEOK, Inc. Employee Stock Award Program, ONEOK issued, for no consideration, to all eligible full-time and
short-term disabled employees, one share of ONEOK common stock when the closing price of ONEOK common stock on the NYSE was for the first time at or above $26 per share. Nine and 10 shares were issued to each named executive officer under this
program in 2006 and 2007, respectively.

(d) This amount was awarded Mr. Kneale for 25 years of service to ONEOK.

Other than as set forth above, the named executive officers did not receive perquisites or other personal benefits with an aggregate value of $10,000 or
more.



|(6) | Effective January 1, 2007, Mr. Kyle became our chairman of the Board of Directors and Mr. Gibson became our president and chief executive officer. Effective
October 16, 2007, Mr. Kyle retired as our chairman of the Board of Directors, Mr. Gibson became our chairman of the Board of Directors in addition to his position as president and chief executive officer, and Mr. Dinan became a
member of our Board of Directors.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Potential Post-Employment Payments and Payments upon a Change in Control

Payments Made Upon Any Termination - Regardless of the manner in which a named executive officers employment terminates, he is entitled to receive amounts
earned during his term of employment. Such amounts include:

| |  |  | accrued but unpaid salary;
| | - |  | --------------------------

| |  |  | amounts contributed under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries and the ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | amounts accrued and vested through the ONEOK retirement plan and supplemental executive retirement plan (SERP).
| | - |  | ---------------------------------------------------------------------------------------------------------------

Payments Made Upon Retirement - In the event of the retirement of a named executive officer, in addition to the items identified above, such named executive
officer will:

| |  |  | be entitled to certain exercise rights with respect to each outstanding and vested stock option granted under the ONEOK LTI Plan;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------

| |  |  | be entitled to receive a prorated portion of each outstanding performance unit granted under the ONEOK Equity Compensation Plan upon the completion of the
performance cycle;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | be entitled to receive a prorated portion of each outstanding restricted stock incentive unit granted under the ONEOK LTI Plan and the ONEOK Equity Compensation
Plan upon completion of the restricted cycle; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | be entitled to receive ONEOK health and life benefits for the retiree and qualifying dependents, as applicable.
| | - |  | ---------------------------------------------------------------------------------------------------------------

Payments Made Upon Death or Disability - In the event of the death or disability of a named executive officer, in addition to the benefits listed under the
headings Payments Made Upon Any Termination and Payments Made Upon Retirement above, the named executive officer will receive benefits under ONEOKs disability plan or payments under ONEOKs life insurance plan, as
appropriate.

Payments Made Upon a Change in Control - Effective January 2005, ONEOK entered into amended and restated termination agreements with
each of our named executive officers. Each termination agreement has an initial two-year term from the date the agreement was entered into and is automatically extended in one-year increments after the expiration of the initial term unless ONEOK
provides notice of non-renewal to the officer, or the officer provides notice of non-renewal to ONEOK, at least 90 days before the January 1 preceding any termination date of the agreement. If a change in control of ONEOK occurs,
the term of each termination agreement will not expire for at least three years after the change in control. Relative to the overall value of the Partnership, the potential benefits payable upon a change in control under these agreements are
comparatively minor.

Effective December 21, 2006, ONEOKs termination agreement with Mr. Kyle was terminated by mutual agreement as a
result of the change in Mr. Kyles position with ONEOK. As a result, Mr. Kyle is not eligible to receive payments in the event of termination following a change in control. Also, effective December 21, 2006, ONEOK entered into an
amended and restated termination agreement with Mr. Gibson which provides for an initial term through January 1, 2008, and is thereafter automatically extended until either party gives written notice of its election to terminate the
agreement 90 days following the date of the notice.

Under the termination agreements, all change in control benefits are double trigger.
Payments and benefits under these termination agreements are payable if the officers employment is terminated by ONEOK without just cause or by the officer for good reason at any time during the three years following a
change in control. In general, severance payments and benefits include a lump sum payment in an amount equal to the sum of (1) for Messrs. Gibson and Kneale three times, and for Messrs. Dinan and Norton two times, the aggregate of the
officers annual salary as then in effect, plus the greater of either the amount of the officers bonus received in the prior year or the officers target bonus for the then current period, and (2) a prorated portion of the
officers target short-term incentive compensation. Messrs. Gibson and Kneale would also be entitled to continuation of health and welfare benefits for 36 months and accelerated benefits under the ONEOK, Inc. 2005 Supplemental Executive
Retirement Plan. Messrs. Dinan and Norton would be entitled to continuation of health and welfare benefits for 24 months. In the case of Messrs. Gibson and Kneale, ONEOK will make gross up payments to them to cover any excise taxes due if any
portion of their severance payments constitutes an excess parachute payment. For Messrs. Dinan and Norton, severance payments will be reduced if the net after-tax benefit to such named executive officer exceeds the net after-tax benefit if such
reduction were not made. ONEOK will make gross up payments to such officers only if the severance payments, as reduced, are subsequently deemed to constitute excess parachute payments.

For the purposes of these agreements, a change in control generally means any of the following events:

| |  |  | an acquisition of ONEOK voting securities by any person that results in the person having beneficial ownership of 20 percent or more of the combined voting power of
ONEOKs outstanding voting securities, other than an acquisition directly from ONEOK;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | the current members of the ONEOK Board, and any new director approved by a vote of at least two-thirds of the ONEOK Board, cease for any reason to constitute at
least a majority of the ONEOK Board, other than in connection with an actual or threatened proxy contest (collectively, the Incumbent Board);
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a merger, consolidation or reorganization with ONEOK or in which ONEOK issues securities, unless (a) ONEOKs shareholders immediately before the
transaction, as a result of the transaction, own, directly or indirectly, at least 50 percent of the combined voting power of the voting securities of ONEOK resulting from the transaction, (b) the members of the ONEOK Incumbent Board after the
execution of the transaction agreement constitute at least a majority of the members of the Board of ONEOK resulting from the transaction, or (c) no person other than persons who, immediately before the transaction owned 30 percent or more of
ONEOKs outstanding voting securities, has beneficial ownership of 30 percent or more of the outstanding voting securities of ONEOK resulting from the transaction; or
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | ONEOK completes the liquidation or dissolution or the sale or other disposition of all or substantially all of ONEOKs assets.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------

For the purposes of these agreements, just cause means the executives conviction in a court of law of a felony, or any crime or offense in a court of
law of a felony, or any crime or offense involving misuse or misappropriation of money or property; the executives violation of any covenant, agreement or obligation not to disclose confidential information regarding our business; any
violation by the executive of any covenant not to compete with us; any act of dishonesty by the executive which adversely affects our business; any willful or intentional act of the executive which adversely affects our business, or reflects
unfavorably on our reputation; the executives use of alcohol or drugs which interferes with the executives performance of duties as our employee; or the executives failure or refusal to perform the specific directives of our Board
of Directors or its officers, which directives are consistent with the scope and nature of the executives duties and responsibilities. The existence and occurrence of all of such causes are to be determined by us, in our sole discretion,
provided, that nothing contained in these provisions of these agreements are to be deemed to interfere in any way with our right to terminate the executives employment at any time without cause.

For the purposes of these agreements, good reason means a demotion, loss of title or significant authority or responsibility of the executive with respect to
the executives employment with us from those in effect on the date of a change in control, a reduction of salary of the executive from that received from us immediately prior to the date of a change in control, a reduction in short-term and/or
long-term incentive targets from those applicable to the executive immediately prior to the date of a change in control, the relocation of our principal executive offices to a location outside the metropolitan area of Tulsa, Oklahoma, or our
requiring a relocation of principal place of employment of the executive, or the failure of a successor corporation to explicitly assume these termination agreements.

Potential Post-Employment Payment Tables-The following tables reflect estimates of the amount of incremental compensation due to each named executive officer in the event of such executives
termination of employment upon death, disability or retirement, termination of employment without cause or termination of employment without cause or with good reason within three years following a change in control. The amounts shown assume that
such termination was effective as of December 31, 2007, and are estimates of the amounts which would be paid out to the executives upon such termination. The actual amounts to be paid out can only be determined at the time of such
executives separation from the Partnership.

In addition to the amounts set forth in the following tables, in the event of termination of employment
for any of the reasons set forth in the tables, each of the named executive officers would receive the following payments or benefits, which had been earned as of December 31, 2007: David L. Kyle, $1,576,417 in exercisable options and $106,089
in pension and SERP benefits; John W. Gibson, $585,977 in exercisable options and $135,667 in pension and SERP benefits; James C. Kneale, $334,826 in exercisable options and $65,977 in pension and SERP benefits; Curtis L. Dinan, $1,990 in pension
and SERP benefits; Pierce H. Norton II, $2,353 in pension and SERP benefits.



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|                                    |  |                                                |           |                          |   |                                         |  |   |           |  | 
|----------------------------------- |  | ---------------------------------------------- | --------- | ------------------------ | - | --------------------------------------- |  | - | --------- |  | 
|David L. Kyle                       |  | Termination UponDeath, Disability, &Retirement |           | TerminationWithout Cause |   | TerminationFollowing a Changein Control |  |  
|INCREMENTAL COMPENSATION            |  |                                                |           |                          |   |                                         |  |   |           |  | 
|(payment contingent on termination) |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Cash Severance                      |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Equity                              |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Restricted Stock/Units              |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Performance Shares/Units            |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Unexercisable Options               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Retirement Benefits                 |  |                                                |           |                          |   |                                         |  |   |           |  | 
|SERP                                |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Other Benefits                      |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Health & Welfare                    |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Tax Gross-Ups                       |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|                                   
|                                    |  |                                                |           |                         
|John W. Gibson                      |  | Termination UponDeath, Disability, &Retirement |           | TerminationWithout Cause |   | TerminationFollowing a Changein Control |  |  
|INCREMENTAL COMPENSATION            |  |                                                |           |                          |   |                                         |  |   |           |  | 
|(payment contingent on termination) |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Cash Severance                      |  | $                                              | -         |                          | $ | -                                       |  | $ | 1,825,673 |  | 
|Equity                              |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Restricted Stock/Units              |  | $                                              | 1,023,550 |                          | $ | 1,023,550                               |  | $ | 3,814,317 |  | 
|Performance Shares/Units            |  | $                                              | 757,190   |                          | $ | -                                       |  | $ | 1,303,492 |  | 
|Unexercisable Options               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | 1,780,740 |                          | $ | 1,023,550                               |  | $ | 5,117,809 |  | 
|Retirement Benefits                 |  |                                                |           |                          |   |                                         |  |   |           |  | 
|SERP                                |  | $                                              | -         |                          | $ | -                                       |  | $ | 114,448   |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | 114,448   |  | 
|Other Benefits                      |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Health & Welfare                    |  | $                                              | -         |                          | $ | -                                       |  | $ | 13,605    |  | 
|Tax Gross-Ups                       |  | $                                              | -         |                          | $ | -                                       |  | $ | 2,688,697 |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | 2,702,302 |  | 
|Total                               |  | $                                              | 1,780,740 |                          | $ | 1,023,550                               |  | $ | 9,760,232 |  | 
|                                   



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|                                    |  |                                                |           |                          |   |                                         |  |   |           |  | 
|----------------------------------- |  | ---------------------------------------------- | --------- | ------------------------ | - | --------------------------------------- |  | - | --------- |  | 
|James C. Kneale                     |  | Termination UponDeath, Disability, &Retirement |           | TerminationWithout Cause |   | TerminationFollowing a Changein Control |  |  
|INCREMENTAL COMPENSATION            |  |                                                |           |                          |   |                                         |  |   |           |  | 
|(payment contingent on termination) |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Cash Severance                      |  | $                                              | -         |                          | $ | -                                       |  | $ | 1,639,526 |  | 
|Equity                              |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Restricted Stock/Units              |  | $                                              | 942,005   |                          | $ | 942,005                                 |  | $ | 1,645,392 |  | 
|Performance Shares/Units            |  | $                                              | 794,428   |                          | $ | -                                       |  | $ | 1,196,648 |  | 
|Unexercisable Options               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | 1,736,433 |                          | $ | 942,005                                 |  | $ | 2,842,040 |  | 
|Retirement Benefits                 |  |                                                |           |                          |   |                                         |  |   |           |  | 
|SERP                                |  | $                                              | -         |                          | $ | -                                       |  | $ | 125,770   |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | 125,770   |  | 
|Other Benefits                      |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Health & Welfare                    |  | $                                              | -         |                          | $ | -                                       |  | $ | 10,487    |  | 
|Tax Gross-Ups                       |  | $                                              | -         |                          | $ | -                                       |  | $ | 1,388,140 |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | 1,398,627 |  | 
|Total                               |  | $                                              | 1,736,433 |                          | $ | 942,005                                 |  | $ | 6,005,963 |  | 
|                                   
|                                    |  |                                                |           |                         
|Curtis L. Dinan                     |  | Termination UponDeath, Disability, &Retirement |           | TerminationWithout Cause |   | TerminationFollowing a Changein Control |  |  
|INCREMENTAL COMPENSATION            |  |                                                |           |                          |   |                                         |  |   |           |  | 
|(payment contingent on termination) |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Cash Severance                      |  | $                                              | -         |                          | $ | -                                       |  | $ | 443,889   |  | 
|Equity                              |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Restricted Stock/Units              |  | $                                              | 114,505   |                          | $ | 114,505                                 |  | $ | 170,950   |  | 
|Performance Shares/Units            |  | $                                              | 207,359   |                          | $ | -                                       |  | $ | 363,268   |  | 
|Unexercisable Options               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | 321,864   |                          | $ | 114,505                                 |  | $ | 534,218   |  | 
|Retirement Benefits                 |  |                                                |           |                          |   |                                         |  |   |           |  | 
|SERP                                |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Other Benefits                      |  |                                                |           |                          |   |                                         |  |   |           |  | 
|Health & Welfare                    |  | $                                              | -         |                          | $ | -                                       |  | $ | 10,117    |  | 
|Tax Gross-Ups                       |  | $                                              | -         |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -         |                          | $ | -                                       |  | $ | 10,117    |  | 
|Total                               |  | $                                              | 321,864   |                          | $ | 114,505                                 |  | $ | 988,224   |  | 
|                                   



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|                                    |  |                                                |         |                          |   |                                         |  |   |           |  | 
|----------------------------------- |  | ---------------------------------------------- | ------- | ------------------------ | - | --------------------------------------- |  | - | --------- |  | 
|Pierce H. Norton II                 |  | Termination UponDeath, Disability, &Retirement |         | TerminationWithout Cause |   | TerminationFollowing a Changein Control |  |  
|INCREMENTAL COMPENSATION            |  |                                                |         |                          |   |                                         |  |   |           |  | 
|(payment contingent on termination) |  |                                                |         |                          |   |                                         |  |   |           |  | 
|Cash Severance                      |  | $                                              | -       |                          | $ | -                                       |  | $ | 952,708   |  | 
|Equity                              |  |                                                |         |                          |   |                                         |  |   |           |  | 
|Restricted Stock/Units              |  | $                                              | 218,272 |                          | $ | 218,272                                 |  | $ | 313,390   |  | 
|Performance Shares/Units            |  | $                                              | 370,289 |                          | $ | -                                       |  | $ | 582,010   |  | 
|Unexercisable Options               |  | $                                              | -       |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | 588,561 |                          | $ | 218,272                                 |  | $ | 895,400   |  | 
|Retirement Benefits                 |  |                                                |         |                          |   |                                         |  |   |           |  | 
|SERP                                |  | $                                              | -       |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -       |                          | $ | -                                       |  | $ | -         |  | 
|Other Benefits                      |  |                                                |         |                          |   |                                         |  |   |           |  | 
|Health & Welfare                    |  | $                                              | -       |                          | $ | -                                       |  | $ | 21,197    |  | 
|Tax Gross-Ups                       |  | $                                              | -       |                          | $ | -                                       |  | $ | -         |  | 
|Total                               |  | $                                              | -       |                          | $ | -                                       |  | $ | 21,197    |  | 
|Total                               |  | $                                              | 588,561 |                          | $ | 218,272                                 |  | $ | 1,869,305 |  | 
|                                   



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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial
Ownership

The following table sets forth the beneficial ownership of our common units and the common stock of ONEOK, the parent company of our general
partner, as of February 1, 2008, by each named executive officer, each member of our Board of Directors of our general partner, and all executive officers and members of our Board of Directors as a group. Other than as set forth below, no
person is known to us to beneficially own more than five percent of our common units.



|                                               |  |              |  |                        |  |              |  |                         |  |                     |  |                 |  |                       |  | 
|---------------------------------------------- |  | ------------ |  | ---------------------- |  | ------------ |  | ----------------------- |  | ------------------- |  | --------------- |  | --------------------- |  | 
|Name and Address ofBeneficial Owner (1)        |  | Common Units |  | Percent ofCommon Units |  | Class BUnits |  | Percent ofClass B Units |  | Percent ofAll Units |  | ONEOKShares (2) |  | Percent ofONEOKShares |  | 
|David L. Kyle                                  |  | 35,000       |  | *                      |  | -            |  | -                       |  | *                   |  | 540,628(3)      |  | *                     |  | 
|John W. Gibson                                 |  | 2,500        |  | *                      |  | -            |  | -                       |  | *                   |  | 149,194(4)      |  | *                     |  | 
|James C. Kneale                                |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | 195,426(5)      |  | *                     |  | 
|Curtis L. Dinan                                |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | 13,660          |  | *                     |  | 
|John R. Barker                                 |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | 9,101           |  | *                     |  | 
|Pierce H. Norton II                            |  | 6,778        |  | *                      |  | -            |  | -                       |  | *                   |  | 3,086           |  | *                     |  | 
|Caron A. Lawhorn                               |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | 19,513(6)       |  | *                     |  | 
|Gary N. Petersen                               |  | 5,892        |  | *                      |  | -            |  | -                       |  | *                   |  | -               |  | -                     |  | 
|Gerald B. Smith                                |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | -               |  | -                     |  | 
|Gil J. Van Lunsen                              |  | -            |  | -                      |  | -            |  | -                       |  | -                   |  | -               |  | -                     |  | 
|All directors and executiveofficers as a group |  | 50,170       |  | *                      |  | -            |  | -                       |  | -                   |  | 930,608         |  | *                     |  | 
|ONEOK, Inc. and affiliates                     |  | 500,000      |  | 1.078                  |  | 36,494,126   |  | 100                     |  | 44.63               |  | -               |  | -                     |  | 



|* | Less than 1 percent.
|- | --------------------

|(1) | The business address for each of the beneficial owners is c/o ONEOK Partners, L.P., 100 West Fifth Street, Tulsa, Oklahoma 74103-4298.
|--- | --------------------------------------------------------------------------------------------------------------------------------------

|(2) | Includes shares of ONEOK common stock held by members of the family of the director or executive officer for which the director or executive officer has sole or shared voting or
investment power, shares of common stock held in ONEOK's Direct Stock Purchase and Dividend Reinvestment Plan, Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries and shares that the board member or executive officer has the right to acquire
within 60 days of February 1, 2008, upon exercise of stock options granted under the LTI Plan.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Includes 196,763 shares exercisable within 60 days of February 1, 2008. Includes 20,000 shares held by Mr. David L. Kyle, 500 shares held by Mr. Kyles son, and
500 shares held by Mr. Kyles step-son. Mr. Kyle disclaims beneficial ownership of these shares.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Includes 59,948 shares exercisable within 60 days of February 1, 2008, and 765 shares of phantom stock under the ONEOK, Inc. Nonqualified Deferred Compensation Plan.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | Includes 65,853 shares exercisable within 60 days of February 1, 2008.
|--- | ----------------------------------------------------------------------

|(6) | Includes 4,745 shares exercisable within 60 days of February 1, 2008.
|--- | ---------------------------------------------------------------------

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related-Person Transactions

Our Board of Directors recognizes that transactions between us and related persons (ONEOK and its subsidiaries, affiliates and their and our executive
officers, directors, and their immediate family members) can present potential or actual conflicts of interest and create the appearance our decisions are based on considerations other than our best interests and our unitholders. Accordingly, as a
general matter, it is our preference to avoid related person transactions. Nevertheless, we recognize that there are situations where related person transactions may be in, or may not be inconsistent with, our best interests and our unitholders
including, but not limited to, situations where we acquire products or services from related persons on an arms length basis on terms comparable to those provided to unrelated third parties.

In the event we enter into a transaction in which ONEOK or its subsidiaries or affiliates or their or our executive officers (other than an employment relationship),
directors, or a members of their immediate family have a direct or indirect material interest, the transaction is presented to our Audit Committee and, if warranted, our Board of Directors for review, to determine if the transaction creates a
conflict of interest and is otherwise fair to us. We require each executive officer and director of our general partner to annually provide us written disclosure of any transaction between the officer or director and us. Our Board of Directors
reviews this disclosure in connection with its annual review of the independence of our Audit Committee. These procedures are not in writing but are evidenced through the meeting agendas of our Board of Directors and our Audit Committee.



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The ONEOK Transactions

For a description of the ONEOK Transactions, see Note B of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K at page 64.

Relationship with ONEOK

ONEOK owns our sole general partner, ONEOK Partners GP, and is able to elect members of our Board of Directors and
our Audit Committee. Other relationships include the following.

Cash Distributions - ONEOK owns approximately 0.5 million of our common units
and approximately 36.5 million of our Class B limited units, which, when combined with its general partner interest, represents an approximate 45.7 percent interest in us. For 2007, we declared total cash distributions to ONEOK of $207.4
million, which included $50.6 million related to its incentive distribution rights. Additional information about our cash distribution policy is included in Item 5, Market for Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities.

Services Agreement - In April 2006, we entered into a Services Agreement with ONEOK, ONEOK Partners GP and
NBP Services. Under the Services Agreement, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK
will provide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financing services, employee benefits provided through ONEOKs benefit plans,
administrative services, insurance and office space leased in ONEOKs headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In
other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees.
However, an expense benefiting the consolidated company but which has no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and
wages. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

In 2007, the aggregate amount charged by
ONEOK, NBP Services and their affiliates to us for their services was approximately $171.7 million.

Operating and Administrative Services
Agreements - ONEOK Partners GP provides certain administrative, operating and management services to us and Midwestern Gas Transmission, Viking Gas Transmission, and Guardian Pipeline through operating agreements. We, along with Midwestern Gas
Transmission, Viking Gas Transmission, and Guardian Pipeline are charged for the salaries, benefits and expenses of ONEOK Partners GP incurred in connection with the operating agreements.

Transportation Agreements - ONEOK Energy Services, a subsidiary of ONEOK, became an affiliate of Northern Border Pipeline in November 2004 in connection with
ONEOKs purchase of ONEOK Partners GP. We do not operate Northern Border Pipeline, but we are a 50 percent owner of the pipeline. In 2007, 3 percent of Northern Border Pipelines design capacity was contracted on a firm basis with ONEOK
Energy Services. Revenue from ONEOK Energy Services for 2007 was $5.1 million. As of January 31, 2008, 3 percent of Northern Border Pipelines design capacity was contracted on a firm basis with ONEOK Energy Services for 2008.

Our Natural Gas Gathering and Processing segment sold $519.8 million of natural gas to ONEOK and its subsidiaries during 2007. Of our Natural Gas Pipelines
segments revenues, $107.0 million were from ONEOK and its subsidiaries during 2007 for both transportation and storage services.

Bushton
Plant - As part of the ONEOK Transactions, we acquired contractual rights to the Bushton Plant that is leased by OBPI. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services at the Bushton
Plant through 2012. We have contracted for all the capacity of the Bushton Plant from OBPI. In exchange for such services, we pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of
OBPIs obligations under equipment leases covering the Bushton Plant.

Derivative Contracts - An affiliate of ONEOK from time to time enters
into commodity derivative contracts on behalf of our Natural Gas Gathering and Processing segment. See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of our derivative instruments and
hedging activities.



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Relationship with TransCanada

As part of the ONEOK Transactions, in April 2006 ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. In 2006, we declared total
cash distributions to TransCanada of $0.7 million, which included $0.5 million related to its incentive distribution rights. Additional information about our cash distribution policy is included in Item 5, Market for Registrants Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

ONEOK Partners GP and TransCanadas affiliate became the operator of
Northern Border Pipeline and entered into a transition services agreement for the transfer of the operator function effective April 1, 2007. Northern Border Pipeline agreed to pay ONEOK Partners GP an amount up to $1.0 million per year for
years 2007 through 2011, to reimburse ONEOK Partners GP for shared equipment and furnishings acquired by ONEOK Partners GP and used to support Northern Border Pipeline operations.

Conflicts of Interest

Our Board of Directors, whose members are designated by our general partner, ONEOK Partners
GP, establishes our business policies.

Our general partner, which is a subsidiary of ONEOK, and its respective affiliates currently engage or may engage
in the businesses in which we engage or in which we may engage in the future. As a result, conflicts of interest may arise between our general partner and its affiliates, and us. If such conflicts arise, the members of our Board of Directors
generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest.

TC PipeLines (a 50 percent owner and operator of
Northern Border Pipeline) and its affiliates are also engaged in interstate natural gas pipeline transportation in the United States separate from their interest in Northern Border Pipeline. As a result, conflicts also may arise between TransCanada
and its affiliates or TC PipeLines and its affiliates, and Northern Border Pipeline. If such conflicts arise, the representatives on the Northern Border Management Committee generally have a fiduciary duty to resolve such conflicts in a manner that
is in the best interest of Northern Border Pipeline.

Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally
require a general partner of a partnership to adhere to fiduciary duty standards under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on our general partners Board of
Directors or the Northern Border Management Committee. Because of the competing interests identified above, our Partnership Agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these
fiduciary duties. For example:

| |  |  | Our Partnership Agreement states that our general partner, its affiliates and their officers and directors will not be liable for damages to us, our limited
partners or their assignees for errors of judgment or for any acts or omissions if the general partner and such other persons acted in good faith.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our Partnership Agreement allows our general partner and our Board of Directors to take into account the interests of other parties in addition to our interests in
resolving conflicts of interest.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our Partnership Agreement provides that our general partner will not be in breach of its obligations under our Partnership Agreement or its duties to us or our
unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in our Partnership Agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might
otherwise be a breach of fiduciary duty.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Our Partnership Agreement provides that a purchaser of common units is deemed to have consented to certain conflicts of interest and actions of our general partner
and its affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partner of any duty stated or implied by law or equity.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | The Audit Committee of our general partner will, at the request of the general partner or a member of our Board of Directors, review conflicts of interest that may
arise between a general partner and its affiliates (or the member of our Board of Directors designated by it), and the unitholders or us. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | The partnership agreement of Northern Border Pipeline relieves us and TC PipeLines, our affiliates, and transferees from any duty to offer business opportunities to
Northern Border Pipeline, subject to specified exceptions.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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We are required to indemnify the general partner, the members of its Board of Directors, and its affiliates and their
respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in
the case of a person other than our general partner) not opposed to, our best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Selection of PricewaterhouseCoopers LLP

On April 26, 2007, the Audit Committee of our Board of Directors approved the dismissal of KPMG LLP and the engagement of PricewaterhouseCoopers LLP as our principal
independent registered public accountant effective with the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2007, on May 2, 2007.

Audit and Non-Audit Fees

Audit services provided by PricewaterhouseCoopers LLP during the 2007 fiscal year and by
KPMG LLP for the 2006 fiscal year included an audit of our consolidated financial statements, an audit of our internal control over financial reporting, audits of the financial statements of certain of our affiliates, review of our quarterly
financial statements, review of debt and equity offerings and related consents and comfort letters, and professional services relating to tax compliance, tax planning, or tax advice.

The following table presents fees billed for audit services rendered (a) by PricewaterhouseCoopers LLP for the audit of annual consolidated financial statements for the year ended December 31, 2007, and fees
billed for other services rendered by PricewaterhouseCoopers LLP during that period, and (b) by KPMG LLP for the audit of our annual consolidated financial statements for the year ended December 31, 2006, and fees billed for other services
rendered by KPMG LLP during that period.



|                       |  |                                  |           |                |   |           |  | 
|---------------------- |  | -------------------------------- | --------- | -------------- | - | --------- |  | 
|                       |  | PricewaterhouseCoopersLLP - 2007 |           | KPMG LLP -2006 |   |          
|Audit fees (1)         |  | $                                | 1,194,070 |                | $ | 1,466,787 |  | 
|Audit-related fees (2) |  |                                  | -         |                |   | 352,135   |  | 
|Tax fees (3)           |  |                                  | 950,342   |                |   | -         |  | 
|All other fees         |  |                                  | 750       |                |   | -         |  | 
|Total                  |  | $                                | 2,145,162 |                | $ | 1,818,922 |  | 
|                      



|(1) | Audit fees consisted of audit work performed in the preparation of financial statements and the audit of internal controls over financial reporting, fees for review of the interim
unaudited financial statements included in our Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission, and fees for special procedures related to regulatory filings.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Audit-related fees consisted principally of fees for audits of the financial statements of our affiliates.
|--- | ----------------------------------------------------------------------------------------------------------

|(3) | Tax fees consisted of fees for tax compliance, tax planning, or tax services, including preparation of our K-1 statements.
|--- | --------------------------------------------------------------------------------------------------------------------------

Audit Committee Policy on Services Provided by Independent Auditor

Consistent with SEC and NYSE policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation, and overseeing the work for the independent auditor. In recognition of this responsibility,
the Audit Committee has established a policy with respect to the pre-approval of audit and permissible non-audit services provided by the independent auditor.

Prior to engagement of PricewaterhouseCoopers LLP as our independent auditor for the 2008 audit, a plan was submitted to and approved by the Audit Committee setting forth the services expected to be rendered during 2008 for each of the
following four categories for its approval:



| | (1) | audit services comprised of audit work performed in the preparation of financial statements and to attest and report on managements assessment of our internal
controls over financial reporting, as well as work that only the independent auditor can reasonably be expected to provide, including quarterly review of our unaudited financial
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | statements, comfort letters, statutory audits, attest services, consents and assistance with the review of documents filed with the SEC;
| | ----------------------------------------------------------------------------------------------------------------------------------------

| | (2) | audit related services comprised of assurance and related services that are traditionally performed by the independent auditor, including due diligence related to mergers and
acquisitions, employee benefit plan audits and consultation regarding financial accounting and/or reporting standards;
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | tax services comprised of tax compliance, tax planning, and tax advice; and
| | --- | ---------------------------------------------------------------------------

| | (4) | all other permissible non-audit services, if any, that the Audit Committee believes are routine and recurring services that would not impair the independence of the auditor.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Audit fees are budgeted and the Audit Committee requires the independent auditor and management to report actual fees versus budgeted fees
periodically during the year by category of service.

The Audit Committee may delegate pre-approval authority to one or more of its members. The member to
whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(1) Exhibits



|    |  |                                                                                                                                                                                                                                                                                                                                                                             
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1 |  | Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated February 14, 2006 (incorporated by reference to
Exhibit 2.1 to Northern Border Partners, L.P.s Form 10-K for the period ended December 31, 2005, filed on March 7, 2006 (File No. 1-12202)).                                    
|    | 
|2.2 |  | First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by
reference to Exhibit 2.2 to Northern Border Partners, L.P.s Form 8-K filed on April 12, 2006 (File No. 1-12202)).                                                             
|    | 
|2.3 |  | Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006 (incorporated by reference to Exhibit 2.2 Northern Border Partners,
L.P.s Form 10-K for the period ended December 31, 2005, filed on March 7, 2006 (File No. 1-12202)).                                                                                  
|    | 
|2.4 |  | First Amendment to Purchase and Sale Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated
by reference to Exhibit 2.4 to Northern Border Partners, L.P.s Form 8-K filed on April 12, 2006 (File No. 1-12202)).                                                        
|    | 
|2.5 |  | Second Amendment to Contribution Agreement by and between ONEOK, Inc. and ONEOK Partners, L.P. dated January 16, 2007 (incorporated by reference to Exhibit 2.5 to ONEOK Partners, L.P.s
report on From 10-K for the year ended December 31, 2006 filed on March 1, 2007 (File No. 1-12202)).                                                                              
|    | 
|2.6 |  | Second Amendment to the Purchase and Sale Agreement by and between ONEOK, Inc. and ONEOK Partners, L.P. dated January 16, 2007 (incorporated by reference to Exhibit 2.6 to ONEOK Partners,
L.P.s report on From 10-K for the year ended December 31, 2006 filed on March 1, 2007 (File No. 1-12202)).                                                                     
|    | 
|2.7 |  | Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership dated as of December 31,
2005 (incorporated by reference to Exhibit 2.3 to Northern Border Partners, L.P.s Form 10-K for the period ended December 31, 2005, filed on March 7, 2006 (File No. 1-12202)).
|    | 
|2.8 |  | Purchase and Sale Agreement by and among Wisconsin Energy Corporation, WPS Investments, LLC and Northern Border Intermediate Limited Partnership dated as of March 30, 2006 (incorporated by
reference to Exhibit 2.1 to Northern Border Partners, L.P.s Form 8-K filed on March 30, 2006 (File No. 1-12202)).                                                             
|    | 
|2.9 |  | Purchase and Sale Agreement by and between Williams Field Services Company, LLC and Northern Border Intermediate Limited Partnership dated as of May 2, 2006 (incorporated by reference to
Exhibit 2.7 to ONEOK Partners, L.P.s Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).                                                 



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|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|---- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.0  |  | First Amendment to Purchase and Sale Agreement and Assignment, Delegation, Acceptance and Assumption of Rights and Obligations by and among Williams Field Services Company, LLC, ONEOK
Partners Intermediate Limited Partnership and ONEOK Overland Pass Holdings, L.L.C. dated as of May 31, 2006 (incorporated by reference to Exhibit 2.8 to ONEOK Partners, L.P.s Form 10-Q for the period ended June 30, 2006, filed on
August 4, 2006 (File No. 1-12202)).
|     | 
|3.1  |  | Northern Border Partners, L.P. Certificate of Limited Partnership dated July 12, 1993, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003
(incorporated by reference to Exhibit 3.1 to Northern Border Partners, L.P.s Form 10-K for the year ended December 31, 2004, filed on March 14, 2005 (File No. 1-12202)).                                                                                               
|     | 
|3.2  |  | Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. dated May 17, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.s
Form 8-K filed on May 23, 2006 (File No. 1-12202)).                                                                                                                                                                                                                       
|     | 
|3.3  |  | Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated as of September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.s
Form 8-K filed on September 19, 2006 (File No. 1-12202)).                                                                                                                                                                                                                  
|     | 
|3.4  |  | Certificate of Formation of ONEOK Partners GP, L.L.C., as amended, dated as of May 15, 2006 (incorporated by reference to Exhibit 3.5 to ONEOK Partners, L.P.s Form 10-Q for the period
ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).                                                                                                                                                                                                        
|     | 
|3.5  |  | Second Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C. effective May 17, 2006 (incorporated by reference to Exhibit 3.6 to ONEOK Partners, L.P.s
Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).                                                                                                                                                                                
|     | 
|3.6  |  | Northern Border Intermediate Limited Partnership Certificate of Limited Partnership dated July 12, 1993, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated
May 20, 2003 (incorporated by reference to Exhibit 3.3 to Northern Border Partners, L.P.s 10-K for the year ended December 31, 2004, filed on March 14, 2005 (File No 1-12202)).                                                                                   
|     | 
|3.7  |  | Certificate of Amendment to Certificate of Limited Partnership of Northern Border Intermediate Limited Partnership dated May 17, 2006 (incorporated by reference to Exhibit 3.3 to ONEOK
Partners, L.P.s Form 8-K filed on May 23, 2006 (File No. 1-12202)).                                                                                                                                                                                                     
|     | 
|3.8  |  | Certificate of Amendment to Certificate of Limited Partnership of ONEOK Partners Intermediate Limited Partnership dated September 15, 2006 (incorporated by reference to Exhibit 3.2 to ONEOK
Partners, L.P.s Form 8-K filed on September 19, 2006 (File No. 1-12202)).                                                                                                                                                                                          
|     | 
|3.9  |  | Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership dated as of May 17, 2006 (incorporated by reference to Exhibit 3.4 to ONEOK
Partners, L.P.s Form 8-K filed on May 23, 2006 (File No. 1-12202)).                                                                                                                                                                                                  
|     | 
|3.10 |  | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership dated as of September 15, 2006 (incorporated by reference to
Exhibit 3.3 to ONEOK Partners, L.P.s Form 8-K filed on September 19, 2006 (File No. 1-12202)).                                                                                                                                                                   
|     | 
|3.11 |  | Certificate of Formation of ONEOK ILP GP, L.L.C. dated May 12, 2006 (incorporated by reference to Exhibit 4.11 to ONEOK Partners, L.P.s Form S-3 filed on September 19, 2006 (File No.
333-137419)).                                                                                                                                                                                                                                                             
|     | 
|3.12 |  | Limited Liability Company Agreement of ONEOK ILP GP, L.L.C. effective May 12, 2006 (incorporated by reference to Exhibit 4.12 to ONEOK Partners, L.P.s Form S-3 filed on September 19,
2006 (File No. 333-137419)).                                                                                                                                                                                                                                              
|     | 
|3.13 |  | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 20, 2007 (incorporated by reference to Exhibit 3.1 to ONEOK Partners,
L.P.s Form 10-Q filed on August 3, 2007 (File No. 1-12202)).                                                                                                                                                                                                             



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|     |  |                                                                                                                                                                                                                                                                                                                                                                         
|---- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.1  |  | Indenture, dated as of June 2, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.1 to Northern Border Partners, L.P.s Form 10-Q for the quarter ended June 30, 2000, filed on August 11, 2000 (File No. 1-12202)).                      
|     | 
|4.2  |  | First Supplemental Indenture, dated as of September 14, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A.
(incorporated by reference to Exhibit 4.2 to Northern Border Partners, L.P.s Form S-4 Registration Statement filed on September 20, 2000, (Registration No. 333-46212)).       
|     | 
|4.3  |  | Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.3 to Northern Border Partners, L.P.s Form 10-K for the year ended December 31, 2001, filed on March 29, 2002 (File No. 1-12202)).                 
|     | 
|4.4  |  | Indenture, dated as of September 25, 2006, between ONEOK Partners, L.P. and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.s Form
8-K filed on September 26, 2006 (File No. 1-12202)).                                                                                                                            
|     | 
|4.5  |  | First Supplemental Indenture, dated as of September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A. , as trustee, with respect
to the 5.90 percent Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.s Form 8-K filed on September 26, 2006 (File No. 1-12202)). 
|     | 
|4.6  |  | Second Supplemental Indenture, dated as of September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A. , as trustee, with
respect to the 6.15 percent Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.s Form 8-K filed on September 26, 2006 (File No. 1-12202)).
|     | 
|4.7  |  | Third Supplemental Indenture, dated as of September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A. , as trustee, with respect
to the 6.65 percent Senior Notes due 2036 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.s Form 8-K filed on September 26, 2006 (File No. 1-12202)). 
|     | 
|4.8  |  | Form of Senior Note due 2012 (included in Exhibit 4.5 above).                                                                                                                                                                                                                                                                                                           
|     | 
|4.9  |  | Form of Senior Note due 2016 (included in Exhibit 4.6 above).                                                                                                                                                                                                                                                                                                           
|     | 
|4.10 |  | Form of Senior Note due 2036 (included in Exhibit 4.7 above).                                                                                                                                                                                                                                                                                                           
|     | 
|4.11 |  | Form of Class B unit certificate (incorporated by reference to Exhibit 4.1 to Northern Border Partners, L.P.s Form 8-K filed on April 12, 2006 (File No. 1-12202)).                                                                                                                                                                                                    
|     | 
|4.12 |  | Form of common unit certificate (included in Exhibit 3.3 above).                                                                                                                                                                                                                                                                                                        
|     | 
|4.13 |  | Fourth Supplemental Indenture, dated as of September 28, 2007, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect
to the 6.85 percent Senior Notes due 2037 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.s Form 8-K filed on September 28, 2007 (File No. 1-12202)). 
|     | 
|4.14 |  | Form of Senior Note due 2037 (included in Exhibit 4.13 above).                                                                                                                                                                                                                                                                                                          
|     | 
|10.1 |  | First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated April 6, 2006 by and between Northern Border Intermediate Limited Partnership and TC
PipeLines Intermediate Limited Partnership (incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Companys Form 8-K filed April 12, 2006 (File No. 333-87753)). 
|     | 
|10.2 |  | Reorganization Agreement, dated September 15, 2006, by and among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership, ONEOK Partners GP, L.L.C. and ONEOK ILP GP, L.L.C.
(incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.s Form 8-K filed on September 19, 2006 (File No. 1-12202)).                                               



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|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.3  |  | Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership (incorporated by reference to Exhibit 10.3 to Northern Border Partners, L.P.s Form 8-K filed on April 12, 2006 (File No. 1-12202)).                                                                                                                                                                                                         
|      | 
|10.4  |  | Amended and Restated Revolving Credit Agreement dated March 30, 2006, among Northern Border Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative
agent, Wachovia Bank, National Association, as Syndication Agent; Bank of Montreal (doing business as Harris Nesbit), Barclays Bank PLC and Citibank, N.A., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Northern Border
Partners, L.P. Form 8-K filed March 31, 2006 (File No. 1-12202)).                                                
|      | 
|10.5  |  | Form of Termination Agreement with ONEOK, Inc. dated as of January 5, 2005 (incorporated by reference to Exhibit 99.1 to Northern Border Partners, L.P.s Form 8-K filed on January 11,
2005 (File No. 1-12202)).                                                                                                                                                                                                                                                                                                                                               
|      | 
|10.6  |  | Amended and Restated Limited Liability Company Agreement of Overland Pass Pipeline Company LLC entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company,
LLC dated May 31, 2006 (incorporated by reference to Exhibit 10.6 to ONEOK Partners, L.P.s Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).                                                                                                                                                                            
|      | 
|10.7  |  | Processing and Gathering Services Agreement between ONEOK Field Services Company, L.L.C, ONEOK, Inc. and ONEOK Bushton Processing, Inc. dated April 6, 2006 (incorporated by reference to
Exhibit 10.7 to ONEOK Partners, L.P.s Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).                                                                                                                                                                                                                                     
|      | 
|10.8  |  | 364-Day Credit Agreement dated April 6, 2006, by and among Northern Border Partners, L.P., the several banks and other financial institutions and lenders from time to time party thereto,
SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co-Documentation Agents (incorporated
by reference to Exhibit 10.1 to ONEOK Partners, L.P.s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
|      | 
|10.9  |  | First Amendment to Amended and Restated Revolving Credit Agreement among ONEOK Partner, L.P., the lenders from time to time party thereto, SunTrust Bank as administrative agent, Wachovia
Bank, National Association, as syndication agent, and BMO Capital Markets Financing, Inc., Barclays Bank PLC and Citibank, N.A. as co-documentation agents, dated December 13, 2006 (incorporated by reference to Exhibit 10.9 to ONEOK Partners,
L.P.s report on From 10-K for the year ended December 31, 2006 filed on March 1, 2007 (File No. 1-12202)).        
|      | 
|10.10 |  | Amended and Restated Revolving Credit Agreement dated March 30, 2007, among ONEOK Partners, L.P., as Borrower, the lenders from time to time party thereto, SunTrust Bank, as Administrative
Agent, Wachovia Bank, National Association, as Syndication Agent, and BMO Capital Markets, Barclays Bank PLC, and Citibank, N.A., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.s report on Form
10-Q filed on May 2, 2007 (File No. 1-12202)).                                                                    
|      | 
|10.11 |  | Supplement and Joinder Agreement dated July 31, 2007, among ONEOK Partners, L.P., as Borrower, each of the existing Lenders, SunTrust Bank, as Administrative Agent, and JPMorgan Chase Bank,
N.A. (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.s report on Form 10-Q filed on August 3, 2007 (File No. 1-12202)).                                                                                                                                                                                                                        
|      | 
|10.12 |  | Underwriting Agreement, dated September 25, 2007, among ONEOK Partners, L.P. and ONEOK Partners Intermediate Limited Partnership and Wachovia Capital Markets LLC, Greenwich Capital Markets,
Inc., and UBS Securities LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.s report on Form 8-K filed on September 28, 2007 (File No. 1-12202)).                                                                                                                                
|      | 
|12.1  |  | Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2007, 2006, 2005, 2004 and 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                             
|      | 
|16.1  |  | Letter from KPMG LLP dated May 2, 2007, to the Securities and Exchange Commission regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to ONEOK Partners,
L.P.s report on Form 8-K filed on May 2, 2007 (File No. 1-12202)).                                                                                                                                                                                                                                                                                                   
|      | 
|21    |  | Required information concerning the registrants subsidiaries.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  



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|     |  |                                                                                                                                                                                      
|---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|23.1 |  | Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.                                                                                               
|     | 
|23.2 |  | Consent of Independent Registered Public Accounting Firm - KPMG LLP.                                                                                                                 
|     | 
|31.1 |  | Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                           
|     | 
|31.2 |  | Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                          
|     | 
|32.1 |  | Certification of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule
13a-14(b)). 
|     | 
|32.2 |  | Certification of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule
13a-14(b)).



|                         |  |                                                                                                                                      |  |      
|------------------------ |  | ------------------------------------------------------------------------------------------------------------------------------------ |  | -----
|(2) Financial Statements |  | Page No.                                                                                                                            
|                         |  |                                                                                                                                     
|(a)                      |  | Reports of Independent Registered Public Accounting Firms                                                                            |  | 53-54
|                         |  |                                                                                                                                     
|(b)                      |  | Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005                                               |  | 55   
|                         |  |                                                                                                                                     
|(c)                      |  | Consolidated Balance Sheets as of December 31, 2007 and 2006                                                                         |  | 56   
|                         |  |                                                                                                                                     
|(d)                      |  | Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005                                           |  | 57   
|                         |  |                                                                                                                                     
|(e)                      |  | Consolidated Statements of Changes in Partners Equity and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005 |  | 58-59
|                         |  |                                                                                                                                     
|(f)                      |  | Notes to Consolidated Financial Statements                                                                                           |  | 60-82

(3) Financial Statement Schedules

All schedules have been omitted because of the absence of conditions under which they are required.

The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of
the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange
Commission.



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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



|                        |  |  |  |                                                    |  |                     |  |                                                                                                               
|----------------------- |  |  |  | -------------------------------------------------- |  | ------------------- |  | --------------------------------------------------------------------------------------------------------------
|                        |  |  |  | ONEOK Partners, L.P.                              
|                        |  |  |  | By: ONEOK Partners GP, L.L.C., its General Partner
|                        |  |  | 
|Date: February 27, 2008 |  |  |  | By:                                                |  | /s/ Curtis L. Dinan
|                        |  |  |  |                                                    |  |                     |  | Curtis L. Dinan                                                                                               
|                        |  |  |  |                                                    |  |                     |  | Senior Vice President,                                                                                        
|                        |  |  |  |                                                    |  |                     |  | Chief Financial Officer and Treasurer (Signing on behalf of the Registrant and as Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities indicated on this 27th day of February 2008.



| |  |                                                             |  |  |  |                                                  
| |  | ----------------------------------------------------------- |  |  |  | -------------------------------------------------
| |  | /s/ John W. Gibson                                          |  |  |  | /s/ Caron A. Lawhorn                             
| |  | John W. Gibson                                              |  |  |  | Caron A. Lawhorn                                 
| |  | Chariman of the Board, President andChief Executive Officer |  |  |  | Senior Vice President andChief Accounting Officer
| |  |                                                             | 
| |  | /s/ Curtis L. Dinan                                         |  |  |  | /s/ Jim Kneale                                   
| |  | Curtis L. Dinan                                             |  |  |  | Jim Kneale                                       
| |  | Director                                                    |  |  |  | Director                                         
| |  |                                                             | 
| |  | /s/ Gil J. Van Lunsen                                       |  |  |  | /s/ Gary N. Petersen                             
| |  | Gil J. Van Lunsen                                           |  |  |  | Gary N. Petersen                                 
| |  | Director                                                    |  |  |  | Director                                         
| |  |                                                             | 
| |  | /s/ Gerald B. Smith                                         |  |  |  |                                                  
| |  | Gerald B. Smith                                             |  |  |  |                                                  
| |  | Director                                                    |  |  |  |                                                  



104