UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
D.C. 20549





FORM
10-K





XANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES


EXCHANGE
ACT OF 1934


For the
fiscal year ended December 31, 2008.


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(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 (§ 229.405) is not contained herein, and will not be contained,
to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, 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 check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes__ No X.





Aggregate
market value of the common units held by non-affiliates based on the closing
trade price on June 30, 2008, was $3.0 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 18, 2009Common
      units
                    
                    54,426,087
      unitsClass
      B units
                    
                    36,494,126
      units


DOCUMENTS INCORPORATED BY REFERENCE:None.









ONEOKPARTNERS, L.P.


2008
ANNUAL REPORT ON FORM 10-K


Part
      I.
            
            Page
      No.Item
      1.
              
              Item
      1A.
              
              Item
      1B.
            Business
              
              Risk Factors
              
              Unresolved Staff Comments
            5-16
              
              16-31
              
              31Item
      2.
            Properties
            31-33Item
      3.
            Legal Proceedings
            33Item
      4.
            Submission of Matters to a Vote of Security
      Holders
            33Part
      II.Item
      5.
            Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchases of Equity Securities
            34-35Item
      6.
            Selected Financial Data
            36Item
      7.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operation
            36-59Item
      7A.
            Quantitative and Qualitative Disclosures about Market
      Risk
            59-61Item
      8.
            Financial Statements and Supplementary
    Data
            62-92Item
      9.
              
              Item
      9A.
              
              Item
      9B.
            Changes in and Disagreements with Accountants on Accounting
      and Financial Disclosure
              
              Controls and Procedures
              
              Other Information
            92
              
              93
              
              93Part
      III.Item
      10.
            Directors, Executive Officers and Corporate
      Governance
            93-97Item
      11.
            Executive Compensation
            97-103Item
      12.
            Security Ownership of Certain Beneficial Owners and
      Management and Related Stockholder Matters
            104Item
      13.
            Certain Relationships and Related Transactions, and
      Director Independence
            104-107Item
      14.
            Principal Accounting Fees and Services
            107-108Part
      IV.Item
      15.
            Exhibits, Financial Statement Schedules
            108-111Signatures
            
            112


As used
in this Annual Report on Form 10-K, “we,” “our,” “us” or the “Partnership”
refers to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate
Limited Partnership and its subsidiaries, unless the context indicates
otherwise.


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GLOSSARY





The
abbreviations, acronyms and industry terminology 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 Pipeline
            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


EBITDA
            Earnings
      before interest, taxes, depreciation and
  amortization


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, 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


MMBbl
            Million
      barrels


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,
Inc.


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, a wholly owned subsidiary of ONEOK,
  Inc.


ONEOK
      Partners GP
            ONEOK
      Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and our sole
      general partner


OPIS
            Oil
      Price Information Service


Overland
      Pass Pipeline Company
            Overland
      Pass Pipeline Company LLC


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Partnership
      Agreement
            Third
      Amended and Restated Agreement of Limited Partnership of ONEOK Partners,
      L.P., as amended


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,” “could,”
“may,” “continue,” “might,” “potential,” “scheduled”  and other words
and terms of similar meaning.  Although we believe that our
expectations regarding future events are based on reasonable assumptions, we can
give no assurance that such expectations or assumptions will be
achieved.  Important factors that could cause actual results to differ
materially from those in the forward-looking statements are described under Part
I,  Item 1A, Risk Factors, and Part II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operation, and
“Forward-Looking Statements,” in this Annual Report on Form 10-K for the year
ended December 31, 2008.


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PART
I




ITEM
1.                     BUSINESS




GENERAL




ONEOK
Partners, L.P. is a publicly traded Delaware master limited partnership that was
formed in 1993.  Our common units are listed on the NYSE under the
trading symbol “OKS.”  We are one of the largest publicly traded
master limited partnerships and a leader in the gathering, processing, storage
and transportation of natural gas in the United States.  In addition,
we own one of the nation’s premier natural gas liquids systems, connecting NGL
supply in the Mid-Continent and Rocky Mountain regions with key market
centers.  We also own a 50 percent equity interest in a leading
transporter of natural gas imported from Canada into the United
States.





DESCRIPTION
OF BUSINESS SEGMENTS





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


·
            our
      Natural Gas Gathering and Processing segment primarily gathers and
      processes unprocessed natural gas;


·
            our
      Natural Gas Pipelines segment primarily owns and 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 owns and operates
      FERC-regulated interstate natural gas liquids gathering and distribution
      pipelines.





For
financial and statistical information regarding our business segments, see below
in the “Segment Financial Information” section, Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operation and Note L of the
Notes to Consolidated Financial Statements in this Annual Report on Form
10-K.





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 47.7
percent aggregate equity interest in us.




Business
Strategy




Our
primary business strategy is to deliver consistent growth and sustainable
earnings while focusing on safe, reliable, environmentally sound and legally
compliant operations for our customers, employees, contractors and the public
through the following:


·
            developing
      and executing internally generated growth
  projects;


·
            executing
      strategic acquisitions that utilize our core competencies;
    and


·
            managing
      our balance sheet over the long term to maintain our credit ratings at or
      above their current investment-grade
levels.





Outlook
for 2009





We expect
continued deteriorating economic conditions in 2009, with downward pressures,
relative to 2008, on commodity prices for natural gas, NGLs and crude oil. 
We anticipate that lower commodity prices will result in reduced drilling
activity and economic conditions will result in reduced petrochemical
demand.  We also expect continued volatility and disruption in the
financial markets, which could result in an increased cost of capital.  We
expect depressed commodity prices and tighter capital markets to also result in
the sale or consolidation of underperforming assets in the industry, which may
present opportunities for us.





We intend
to pursue growth in our natural gas businesses through well-connects and
contract renegotiations and through expansions and extensions of our existing
systems and plants.  For our natural gas liquids businesses, we intend to
continue to focus on adding new supply connections, optimizing existing assets,
as well as completing our growth projects currently


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under
construction.  Capital expenditures in 2009 are expected to be
significantly lower than in 2008 when we spent approximately $1.3
billion.  We plan to spend approximately $425 million on capital
expenditures in 2009, of which approximately $355 million is for growth
projects.  We also plan to pursue strategic acquisitions related to
gathering, processing, fractionating, storing, transporting and marketing
natural gas and NGLs.





SIGNIFICANT
DEVELOPMENTS IN 2008





Capital Projects - The
following projects were placed in-service during 2008:


·
            January
      - Midwestern Gas Transmission’s eastern extension
  pipeline;


·
            July
      - final phase of Fort Union Gas Gathering expansion
    project;


·
            September
      - Woodford Shale natural gas liquids pipeline
  extension;


·
            October
      - Bushton fractionation expansion;


·
            November
      - Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas;
      and


·
            December
      - partial operations of the Guardian Pipeline extension with interruptible
      service from Ixonia, Wisconsin, to Green Bay,
  Wisconsin.





Equity Issuance - In March
2008, we completed a public offering of 2.5 million common units at $58.10 per
common unit, generating net proceeds of approximately $140.4 million after
deducting underwriting discounts but before offering expenses.  In
addition, we sold 5.4 million common units to ONEOK in a private placement,
generating proceeds of approximately $303.2 million.  In conjunction
with the public offering of common units and the private placement, ONEOK
Partners GP contributed $9.4 million in order to maintain its 2 percent general
partner interest in us.





In April
2008, we sold an additional 128,873 common units at $58.10 per common unit to
the underwriters of the public offering upon the partial exercise of their
option to purchase additional common units to cover
over-allotments.  We received net proceeds of approximately $7.2
million from the sale of the common units after deducting underwriting discounts
but before offering expenses.  In conjunction with the partial
exercise by the underwriters, ONEOK Partners GP contributed $0.2 million in
order to maintain its 2 percent general partner interest in us.  As a
result of these transactions, ONEOK now holds a 47.7 percent aggregate equity
interest in us.





SEGMENT
FINANCIAL INFORMATION





Operating Income - The
following table sets forth (i) operating income and (ii) operating income
including the impact of equity earnings from investments by segment, as a
percentage of our consolidated total, excluding any gain or (loss) on sale of
assets, for the periods indicated.





Operating
      Income andOperating
      Income
                                  Equity
      Earnings from InvestmentsYears
      Ended December 31,
                                  Years
      Ended December 31,2008
                                  2007
                                  2006
                                  2008
                                  2007
                                  2006Natural
      Gas Gathering and Processing
                                  38%
                                  42%
                                  46%
                                  38%
                                  40%
                                  41%Natural
      Gas Pipelines
                                  21%
                                  25%
                                  31%
                                  27%
                                  33%
                                  40%Natural
      Gas Liquids Gathering and Fractionation
                                  32%
                                  25%
                                  22%
                                  27%
                                  21%
                                  18%Natural
      Gas Liquids Pipelines
                                  9%
                                  9%
                                  7%
                                  8%
                                  8%
                                  6%Other
      and Eliminations
                                  *
                                  (1%)
                                  (6%)
                                  *
                                  (2%)
                                  (5%)Total
                                  100%
                                  100%
                                  100%
                                  100%
                                  100%
                                  100%*
      Represents a value of less than 1 percent.




Customers and Total Assets -
See Note L of the Notes to Consolidated Financial Statements in this Annual
Report on Form 10-K for discussion of revenues from external customers under
“Customers” and disclosure of total assets by segment within the “Operating
Segment Information” table.




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Intersegment Revenues - The
following table sets forth the percentage of intersegment revenues to total
revenue, by segment, for the periods indicated.





Years
      Ended December 31,Intersegment
      Revenues
                              2008
                              2007
                              2006Natural
      Gas Gathering and Processing
                              39%
                              35%
                              35%Natural
      Gas Pipelines
                              *
                              *
                              *Natural
      Gas Liquids Gathering and Fractionation
                              *
                              *
                              *Natural
      Gas Liquids Pipelines
                              60%
                              83%
                              100%*
      Represents a value of less than 1 percent.





See Note
L of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional information about intersegment revenues.





NARRATIVE
DESCRIPTION OF BUSINESS





Natural
Gas Gathering and Processing





Business Strategy -We focus on safe,
environmentally sound and legally 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 price exposure.  We also seek to provide reliable, efficient
and consistent operations through optimization of our natural gas gathering and
processing operations while managing costs.





Description of Business -Our operations include
gathering of unprocessed natural gas produced from crude oil and natural gas
wells.  We gather unprocessed 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 unprocessed natural gas in
two producing basins in the Rocky Mountain region: the Williston Basin, which
spans portions of Montana, North Dakota and the Canadian province of
Saskatchewan, and the Powder River Basin of Wyoming.





Our
gathering and processing operations are non-discretionary services required by
our customers to move their unprocessed natural gas from the producing regions
to end users for consumption.  In the Mid-Continent and Rocky Mountain
regions, unprocessed natural gas is compressed and transported through pipelines
to processing facilities where volumes are aggregated, treated and processed to
remove water vapor, solids and other contaminants, and to extract NGLs in order
to provide marketable natural gas, commonly referred to as residue
gas.   The residue gas, which consists primarily of methane, is
compressed and delivered to natural gas pipelines for transportation to end
users.  When the NGLs are separated from the unprocessed natural gas
at the processing plants, the NGLs are generally in the form of a mixed,
unfractionated NGL stream.  This unfractionated NGL stream is
generally shipped to fractionators where, through the application of 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).  Our natural gas and
NGL products are sold to affiliates and a diverse customer base.





Our
natural gas processing operations utilize straddle and field gas processing
plants to extract NGLs from unprocessed natural gas and remove water vapor and
other contaminants from the unprocessed 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 process
natural gas gathered from multiple producing wells.





Our
Natural Gas Gathering and Processing segment gathers and processes unprocessed
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 unprocessed 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.  For 2008, this type of contract
      represented approximately 34 percent of contracted
      volumes.  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


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-
            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 that
      is based on 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 typically takes its NGLs and residue gas in-kind.  This
      type of contract primarily exposes us to volumetric risk with minimal
      commodity price risk.  Our POP and keep-whole contracts also
      typically include fee provisions.  For 2008, this type of
      contract represented approximately 58 percent of contracted
      volumes.


·
            Keep-Whole
      - Under a keep-whole processing contract, we extract NGLs from the
      unprocessed natural gas and return to the producer volumes of residue gas
      containing the same amount of Btus as the unprocessed natural gas that was
      delivered to us.  We retain the NGLs as our fee for
      processing.  Accordingly, we must purchase and return to the
      producer sufficient volumes of 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 unprocessed 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.  For 2008, this type of contract represented
      approximately 8 percent of contracted volumes, with approximately 89
      percent of that contracted volume containing language that effectively
      converts these contracts into fee contracts when the gross processing
      spread is negative.  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.





Revenues
of this segment are 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.





Unconsolidated Affiliates -
Our Natural Gas Gathering and Processing segment has the following
unconsolidated affiliates:


·
            49
      percent ownership interest in Bighorn Gas Gathering, which operates a
      major coalbed methane gathering system serving a broad production area in
      northeast Wyoming;


·
            37
      percent ownership interest in Fort Union Gas Gathering, which gathers
      coalbed methane gas produced in the Powder River Basin and delivers
      natural gas into the interstate pipeline
grid;


·
            35
      percent ownership interest in Lost Creek Gathering Company, which gathers
      natural gas produced from conventional wells in the Wind River Basin of
      central Wyoming and delivers natural gas into the interstate pipeline
      grid; and


·
            10
      percent ownership interest in Venice Energy Services Co., LLC, a gas
      processing complex near Venice,
Louisiana.





See Note
M of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional discussion of unconsolidated 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, exploration success, available
capital and regulatory control.  Relatively high natural gas and crude
oil prices resulted in increased drilling for most of 2008 in the Mid-Continent
and Rocky Mountain regions, which are our primary supply
regions.  Significant price declines and reduced drilling activity
beginning in the fourth quarter of 2008 are now creating less favorable
near-term supply projections.





In the
Mid-Continent region, our gathering and processing assets 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.





In the
Williston Basin, we connected more wells in 2008 than in prior years as a result
of increased drilling activity.  While transportation and refining
capacity constraints for crude oil continue to moderately impact natural gas
production in the Williston Basin, the recent reduction in commodity prices has
decreased drilling activity.





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


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plant
operations can be adjusted to respond to market conditions, such as demand for
ethane.  By changing operating parameters at certain plants, 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 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.  We are also exposed to 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
other consumers.





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 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.  The factors that typically affect our ability to compete for
natural gas supplies are:


·
            producer
      drilling activity;


·
            the
      petrochemical industry’s level of capacity utilization and its specific
      feedstock requirements;


·
            fees
      charged under our contracts;


·
            pressures
      maintained on our gathering
systems;


·
            location
      of our gathering systems relative to our
  competitors;


·
            location
      of our gathering systems relative to drilling
  activity;


·
            efficiency
      and reliability of our operations;
and


·
            delivery
      capabilities that exist in each system and plant
  location.





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.  The
principal goal of the contract renegotiation effort is to eliminate unprofitable
contracts and improve margins, primarily during periods when the gross
processing spread is negative.





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.





Additionally,
the operations of our assets are regulated by various state and federal
government agencies.  See further discussion in the “Environmental and
Safety Matters” section.




Natural
Gas Pipelines




Business Strategy- We focus
on safe, environmentally sound and legally compliant operations for our
employees, contractors, customers and the public.  We seek to maintain
a competitive cost structure and increase throughput and growth


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of our
existing natural gas pipelines and storage assets through extensions and
expansions supported by long-term transportation and reservation
contracts.





Description of Business- Our
Natural Gas Pipelines segment primarily owns and 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, Iowa, Illinois, Indiana, Kentucky, Tennessee,
Oklahoma, Texas and New Mexico.  Our interstate pipelines
include:


·
            Midwestern
      Gas Transmission, which is a bi-directional system that interconnects with
      Tennessee Gas Transmission Company near Portland, Tennessee, and with
      several interstate pipelines near Joliet,
  Illinois;


·
            Viking
      Gas Transmission, which transports natural gas from an interconnection
      with TransCanada near Emerson, Manitoba, to an interconnection with ANR
      Pipeline Company near Marshfield,
Wisconsin;


·
            Guardian
      Pipeline interconnects with several pipelines in Joliet, Illinois, and
      with local distribution companies in Wisconsin;
  and


·
            OkTex
      Pipeline, which 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.  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
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
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.





Unconsolidated Affiliates -
Our Natural Gas Pipelines segment has the following unconsolidated
affiliates:


·
            50
      percent interest in Northern Border Pipeline, which transports natural gas
      from the Montana-Saskatchewan border near Port Morgan, Montana, to a
      terminus near North Hayden, Indiana;
and


·
            48
      percent ownership interest in Sycamore Gas System, which is a gathering
      system with compression located in south central
  Oklahoma.





See Note
M of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional discussion of unconsolidated 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.  Guardian Pipeline and Midwestern Gas
Transmission access supply from the major


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producing
regions of the Mid-Continent, Rocky Mountain, Canada and Gulf
Coast.  The supply of natural gas to our 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 Rocky Mountain and Mid-Continent regions, including the
Anadarko Basin, Hugoton Basin, Central Kansas Uplift Basin, Permian Basin,
Williston Basin and Powder River Basin.  United States natural gas
drilling rig counts increased in 2008, compared with 2007, but rig counts began
to decline towards the end of 2008 and continuing into 2009.





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 producers’
decisions related to the production of natural gas, the level of NGLs processed
from natural gas and natural gas storage injection and withdrawal
activity.





Commodity Prices - We
are exposed to market risk when existing contracts expire and are subject to
renegotiation with customers that have competitive alternatives and analyze the
market price 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 changes in the 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.  Cold temperatures can lead to
greater demand for our transportation services due to increased demand for
natural gas to heat residential and commercial properties.  Low
precipitation levels can impact the demand for natural gas that is used to fuel
irrigation activity in the Mid-Continent region.





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





Natural
gas storage is necessary to balance the relatively steady natural gas supply
with the seasonal demand of residential, commercial and electric power
generation users.  The majority of our storage capacity is contracted
under term agreements.  A small portion of our storage capacity is
retained for operational purposes and seasonal market activity.





Competition-Our natural gas
pipelines compete directly with other intrastate and interstate pipeline
companies and other storage facilities for natural gas.  Our natural
gas assets primarily serve local distribution companies, large industrial
companies, municipalities, irrigation customers, power generation facilities and
marketing companies.  Competition among pipelines and natural gas
storage facilities is based primarily on fees for services, quality of services
provided, current and forward natural gas prices, and proximity to natural gas
supply areas and markets.  Competition for natural gas transportation
services continues to increase as the FERC and state regulatory bodies continue
to encourage more competition in the natural gas markets.  We believe
that we compete effectively with our pipelines and storage assets due to their
strategic locations connecting supply areas to market centers and other
pipelines.





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.  In
Kansas and Texas, natural gas storage may be regulated by the state and by the
FERC for certain types of services.  In Oklahoma, natural gas
gathering and storage are not subject to rate regulation and have market-based
rate authority for certain types of services.





Additionally,
the operations of our assets are regulated by various state and federal
government agencies.  See further discussion in the “Environmental and
Safety Matters” section.




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Natural
Gas Liquids Gathering and Fractionation





Business Strategy - We focus
on safe, environmentally sound and legally 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 products in the
Mid-Continent and Gulf Coast regions.





Description of Business-Our natural gas liquids
gathering and fractionation assets consist of facilities that gather,
fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas
and Texas, as well as store and fractionate NGLs and NGL products in Mont
Belvieu, Texas.  Most of the pipeline-connected natural gas processing
plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from
unprocessed natural gas, are connected to our gathering systems.





Most
natural gas produced at the wellhead contains a mixture of NGL components such
as ethane, propane, iso-butane, normal butane and natural
gasoline.  Natural gas processing plants remove the NGLs from the
natural gas stream to realize the higher economic value of the NGLs and to meet
natural gas pipeline quality specifications, which limit NGLs in the natural gas
stream due to liquid and Btu content.  The NGLs that are separated
from the natural gas stream at the natural gas processing plants remain in a
mixed, unfractionated form until they are gathered, primarily by pipeline, and
delivered to fractionators.





Our
natural gas liquids gathering and fractionation operations are non-discretionary
services required by our customers to convert their mixed, unfractionated NGLs
into marketable purity products.  A fractionator, through the
application of heat and pressure, separates the unfractionated NGL stream into
marketable purity products, such as ethane, ethane/propane mix, propane,
iso-butane, normal butane and natural gasoline (collectively, NGL
products).  These NGL products are then stored or distributed to our
customers, such as petrochemical manufacturers, heating fuel users, 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.  We also purchase NGLs and condensate from third parties as
well as from our Natural Gas Gathering and Processing segment.





Revenues
for our Natural Gas Liquids Gathering and Fractionation segment are primarily
derived 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 assets, contract portfolio and market
      knowledge to capture locational and seasonal price
      differentials.  We move NGL products between Conway, Kansas, and
      Mont Belvieu, Texas, in order to capture the locational price
      differentials between the two market centers.  Our NGL storage
      facilities are also utilized to capture seasonal price
      variances.


·
            Our
      isomerization business captures the price differential 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
      increase the octane of motor
gasoline.


·
            Our
      storage business collects fees to store NGLs at our Mid-Continent and Mont
      Belvieu facilities.





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 liquid 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 Rocky Mountain regions.





Our
natural gas liquids gathering pipelines are also affected by operational or
market-driven changes that impact the output of natural gas processing plants to
which they are connected.  The differential between the composite
price of NGL products and the price of natural gas, particularly the
differential between the price of ethane and the price of natural gas, may
influence processing plant NGL output.  Historically, 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 generally provided a
positive processing spread.  For the majority of 2008, ethane prices
remained above natural gas prices on a relative basis, which resulted in ethane
recovery from processing plants that deliver NGLs to our natural gas liquids
gathering pipelines.   Similar to the pricing environments we experienced
in September and December of 2008, we expect ethane prices in 2009, at times, to
be below natural gas prices, with some processing plants connected to our
natural gas liquids gathering pipelines reducing ethane
production.


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Demand - Demand for
NGLs and the ability of natural gas processors to successfully and economically
sustain their operations impacts the volume of unfractionated NGLs produced by
natural gas processing plants, thereby affecting the demand for NGL gathering
and fractionation services.  Natural gas and propane are subject to
weather-related seasonal demand.  Other NGL products are affected by
economic conditions and the demand associated with the various industries that
utilize the commodity, such as butanes and natural gasoline, which are used by
the refining industry as blending stocks for motor
fuel.  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 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 gathering and
fractionation business competes with other fractionators, storage providers and
gatherers for NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast
regions.  The factors that typically affect our ability to compete for
NGL supplies are:


·
            producer
      drilling activity;


·
            the
      petrochemical industry’s level of capacity utilization and feedstock
      requirements;


·
            fees
      charged under our contracts;


·
            pressures
      maintained on our gathering
systems;


·
            location
      of our gathering systems relative to our
  competitors;


·
            location
      of our gathering systems relative to drilling
  activity;


·
            efficiency
      and reliability of our operations;
and


·
            delivery
      capabilities that exist in each system, plant and storage
      location.





We are
responding to these industry conditions by making capital investments to access
new supplies, increase gathering and fractionation capacity, increase storage
capabilities and reduce operating costs so that we may effectively
compete.





Government Regulation -
Revenues generated by our pipelines in both Oklahoma and Kansas are not
regulated by the FERC or those states’ respective corporation
commissions.  However, the operations of our assets are regulated by
various state and federal government agencies.  See further discussion
in the “Environmental and Safety Matters” section.




Natural
Gas Liquids Pipelines




Business Strategy- We focus
on safe, environmentally sound and legally compliant operations for our
employees, contractors, customers and the public.  We seek to increase
throughput and to continue to provide cost-effective transportation of NGLs
between the Rocky Mountain, Mid-Continent and Gulf Coast regions 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.





Description of Business- Our
Natural Gas Liquids Pipelines segment primarily owns and 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, the Texas
panhandle and the Rocky Mountain region to our Natural Gas Liquids Gathering and
Fractionation segment’s Mid-Continent fractionation facilities in Oklahoma and
Kansas.  Our natural gas liquids distribution pipelines deliver
unfractionated NGLs and 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 Energy Partners, L.P. (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 Midwest markets, including Chicago, Illinois.  We operate
FERC-regulated natural gas liquids gathering and distribution pipelines
in


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Oklahoma,
Kansas, Nebraska, Missouri, Iowa, Illinois, Indiana, Texas, Wyoming and
Colorado.  We have product terminal and storage facilities in Missouri,
Nebraska, Iowa and Illinois.





Revenues
for this segment are 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 primarily offered through 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 charge some customers storage lease fees to reserve a
specific storage capacity, and we charge some customers based on the quantity of
capacity utilized.





Unconsolidated Affiliates -
Our Natural Gas Liquids Pipelines segment has the following unconsolidated
affiliates:


·
            50
      percent ownership interest in Chisholm Pipeline Company, which operates an
      interstate natural gas liquids pipeline system extending approximately 184
      miles from origin points in Oklahoma and Kansas;
  and


·
            50
      percent ownership interest in Heartland, which operates a terminal and
      pipeline system that transports refined petroleum products in Kansas,
      Nebraska and Iowa.





See Note
M of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional discussion of unconsolidated affiliates.





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 liquid content of the natural gas that is produced and
processed.  The unfractionated NGLs that we transport and store are
primarily gathered from natural gas processing plants in Oklahoma, Kansas, the
Texas panhandle and the Rocky Mountain region.  The supply of NGLs
gathered are affected by operational or market-driven changes that impact the
NGL 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.  Historically, 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 generally provided a positive processing spread.  For the
majority of 2008, ethane prices remained above natural gas prices on a relative
basis, which resulted in ethane recovery from processing plants that deliver
NGLs to our natural gas liquids gathering pipelines.  Similar to the
pricing environments we experienced in September and December of 2008, we expect
ethane prices in 2009, at times, to be below natural gas prices, with some
processing plants connected to our natural gas liquids gathering pipelines
reducing ethane production.





Demand - Demand for
NGLs and the ability of natural gas processors to successfully and economically
sustain their operations impacts the volume of unfractionated NGLs produced by
natural gas processing plants, 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 Gulf Coast regions is narrow, NGL shipments may decline,
resulting in a reduction of transportation revenues.





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


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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 compete directly with other intrastate and interstate pipeline
companies and other storage facilities for NGLs.  Competition among
pipeline companies and NGL storage facilities is based primarily on fees for
services, quality of services provided, current and forward NGL prices and
proximity to natural gas liquids supply areas and markets.  We believe
that we compete effectively with our pipelines and storage assets due to their
strategic locations connecting supply areas to market centers.





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, fees for services, depreciation and amortization
policies, and initiation and discontinuation of services.  The KCC
regulates intrastate transportation of NGLs and refined products in
Kansas.





Additionally,
the operations of our assets are regulated by various state and federal
government agencies.  See further discussion in the “Environmental and
Safety Matters” section.





Other





Description of Business - Our
Other segment includes Black Mesa Pipeline, a 273-mile pipeline designed to
transport crushed coal suspended in water that originates at a coal mine in
Kayenta, Arizona, and terminates at the Mohave Generating Station (Mohave) in
Laughlin, Nevada.  Operations for Mohave ceased on December 31,
2005.  Also on December 31, 2005, Black Mesa Pipeline’s transportation
contract with the coal supplier of Mohave expired, and our coal slurry pipeline
operations were shut down.  In the second quarter of 2008, we started
the decommissioning of Black Mesa Pipeline.  The duration of the
decommissioning process will depend on, among other factors, the arrangements we
make with land owners as to the transfer, abandonment or removal of property on
their lands.  We do not expect the decommissioning to have a material
impact on our consolidated financial statements.





ENVIRONMENTAL
AND SAFETY MATTERS





Information
about our environmental matters is included in Note J 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 regulations, including
integrity management regulations.  The Pipeline Safety Improvement Act
requires pipeline companies to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically
designated high consequence areas.  To our knowledge, we are in
compliance with all material requirements associated with the various pipeline
safety regulations.





Air and Water Emissions - The
federal Clean Air Act, the federal 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
federally enforceable 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 of
pollutants discharged to waters of the United States and remediation of waters
affected by such discharge.  To our knowledge, we are in compliance
with all material requirements associated with the various
regulations.





The
United States Congress is actively considering legislation to reduce emissions
of greenhouse gases, including carbon dioxide and methane.  In
addition, state and regional initiatives to regulate greenhouse gas emissions
are underway.  We are monitoring federal and state legislation to
assess the potential impact on our operations.  Our most recent
calculation of direct greenhouse gas emissions is estimated to be less than 6
million metric tons of carbon dioxide equivalents on an annual
basis.  We will continue efforts to quantify our direct greenhouse gas
emissions and will report such emissions as required by any mandatory reporting
rule, including the rules anticipated to be issued by the EPA in
mid-2009.





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.




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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.  We completed the Homeland Security assessments, and our
facilities were subsequently assigned one of four risked-based tiers ranging
from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low
risk.  A majority of our facilities were not tiered.  We are
currently waiting for Homeland Security’s analysis to determine if any of the
tiered facilities will require Site Security Plans and possible physical
security enhancements.





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) developing and maintaining an accurate greenhouse gas emissions
inventory, according to rules anticipated to be issued by the EPA in mid-2009,
(ii) improving the efficiency of our various pipelines, natural gas processing
facilities and natural gas liquids fractionation facilities, (iii) following
developing technologies for emissions control, (iv) following developing
technologies to capture carbon dioxide to keep it from reaching the atmosphere,
and (v) analyzing options for future energy investment.





We
participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane
emissions.  We were honored in 2008 as the “Natural Gas STAR Gathering
and Processing Partner of the Year” for our efforts to positively address
environmental issues through voluntary implementation of emission-reduction
opportunities.  In addition, we continue to focus on maintaining low
rates of lost-and-unaccounted-for methane gas through expanded implementation of
best practices to limit the release of methane gas during pipeline and facility
maintenance and operations.  Our most recent calculation of our annual
lost-and-unaccounted-for natural gas, for all of our business operations, is
less than 1 percent of total throughput.





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, 2009, we utilized the services of 1,232 people in addition to the
other resources provided by ONEOK and its affiliates.




AVAILABLE
INFORMATION




We make
available on our Web site 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,
Partnership Agreement and the written charter of our Audit Committee are also
available on our Web site, and we will make available, free of charge, copies of
these documents upon request.  However, our Web site and any contents
thereof are not incorporated by reference into this document.




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




Current
levels of market volatility are unprecedented.





The
capital and credit markets have been experiencing volatility and
disruption.  During the fourth quarter of 2008, the volatility and
disruption reached unprecedented levels.  In many cases, the capital
markets have exerted downward pressure on equity prices and reduced the credit
capacity for companies.  Our ability to grow could be constrained if
we do not have


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regular
access to the capital and credit markets. If current levels of market disruption
and volatility continue or worsen, our access to capital and credit markets
could be disrupted, making growth through acquisitions and development projects
difficult or impractical to pursue until such time as markets
stabilize.





Our
operating results may be adversely affected by unfavorable economic and market
conditions.





Economic
conditions worldwide have from time to time contributed to slowdowns in the oil
and gas industry, as well as in the specific segments and markets in which we
operate, resulting in reduced demand and increased price competition for our
products and services.  Our operating results in one or more
geographic regions may also be affected by uncertain or changing economic
conditions within that region.  Volatility in commodity prices might
have an impact on many of our customers, which, in turn, could have a negative
impact on their ability to meet their obligations to us.  If global
economic and market conditions (including volatility in commodity markets), or
economic conditions in the United States or other key markets, remain uncertain
or persist, spread or deteriorate further, we may experience material impacts on
our business, financial condition and results of operations.





The
recent downturn in the credit markets has increased the cost of borrowing and
has made financing difficult to obtain, each of which may have a material
adverse effect on our results of operations and business.





Recent
events in the financial markets have had an adverse impact on the credit
markets.  As a result, credit has become more expensive and difficult
to obtain.  Some lenders are imposing more stringent restrictions on
the terms of credit and there may be a general reduction in the amount of credit
available in the markets in which we conduct business.  The negative
impact of the tightening of the credit markets or a further tightening may have
a material adverse effect on us resulting from, but not limited to, an inability
to obtain credit necessary to expand facilities or finance the acquisition of
assets on favorable terms, if at all, increased financing costs or financing
with increasingly restrictive covenants.





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 volatile and are likely to
continue to be so in the future.  Recent significant and steep
commodity price declines and compressions in commodity price differentials have
had and could continue to have material negative impacts on our financial
results.  The prices we receive for our commodities are subject to
wide fluctuations in response to a variety of factors beyond our control,
including the following:


·
            overall
      domestic and global economic
conditions;


·
            relatively
      minor changes in the supply of, and demand for, domestic and foreign
      energy;


·
            market
      uncertainty;


·
            the
      availability and cost of transportation
  capacity;


·
            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;


·
            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
may not be able to generate sufficient cash from operations to allow us to pay
quarterly distributions at current levels following establishment of cash
reserves and payment of fees and expenses, including payments to our
affiliates.





The
amount of cash we can distribute to our unitholders principally depends upon the
cash we generate from our operations.  Because the cash we generate
from operations will fluctuate from quarter to quarter, we may not be able to
maintain future quarterly distributions at the current level.  Our
ability to pay quarterly distributions depends primarily on cash flow, including
cash flow from financial reserves and working capital borrowings, and not solely
on profitability, which is affected


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by
non-cash items.  As a result, we may pay cash distributions during
periods when we record net losses and may be unable to pay cash distributions
during periods when we record net income.





We
do not fully hedge against 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 exposures arise from commodity prices with
respect to our processing agreements, the differentials between NGL and natural
gas prices with respect to our natural gas and NGL transportation, fractionation
and exchange agreements, the differential between the individual NGL products
and the differentials in natural gas and NGLs in storage utilized by our
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.





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 and cash flows.





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





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





Acquisitions that appear to be
accretive may nevertheless reduce our cash from operations on a per unit
basis.





Any
acquisition involves potential risks that may include, among other
things:




·
            mistaken
      assumptions about volumes, revenues and costs, including
    synergies;


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·
            an
      inability to successfully integrate the businesses we
acquire;·
            decrease
      in our liquidity as a result of our using a significant portion of our
      available cash or borrowing capacity to finance the
      acquisition;


·
            a
      significant increase in our interest expense or financial leverage if we
      incur additional debt to finance the
  acquisition;


·
            the
      assumption of unknown liabilities for which we are not indemnified or for
      which our indemnity is inadequate;


·
            an
      inability to hire, train or retain qualified personnel to manage and
      operate the acquired business and
assets;


·
            limitations
      on rights to indemnity from the
seller;


·
            mistaken
      assumptions about the overall costs of equity or
  debt;


·
            the
      diversion of management’s and employees’ attention from other business
      concerns;


·
            unforeseen
      difficulties operating in new product areas or new geographic
      areas;


·
            increased
      regulatory burdens;


·
            customer
      or key employee losses at an acquired business;
  and


·
            increased
      regulatory requirements.





If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly, and investors will not have the opportunity to
evaluate the economic, financial and other relevant information that we will
consider in determining the application of these funds and other
resources.





We
do not own all of the land on which our pipelines and facilities are located,
which could disrupt our operations.





We do not
own all of the land on which certain of our pipelines and facilities are
located, and we are, therefore, subject to the risk of increased costs to
maintain necessary land use.  We obtain the rights to construct and
operate certain of our pipelines and related facilities on land owned by third
parties and governmental agencies for a specific period of time.  Our
loss of these rights, through our inability to renew right-of-way contracts, or
increased costs to renew such rights, could have a material adverse effect on
our financial condition, results of operations and cash flows.





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, hurricanes, 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, and we are not fully insured
against all risks inherent to our business.  Additionally, in
accordance with typical industry practice, we do not have any property insurance
on any of our underground pipeline systems that would cover damage to such
systems.





As a
result of market conditions, premiums and deductibles for certain insurance
policies can increase substantially, and in some instances, certain insurance
may become unavailable or available only for reduced amounts of
coverage.  For example, changes in the insurance markets subsequent to
the terrorist attacks on September 11, 2001 and the hurricanes in 2005 and 2008
have made it more difficult for us to obtain certain types of
coverage.  Consequently, we may not be able to renew existing
insurance policies or procure other desirable insurance on commercially
reasonable terms, if at all.  If we were to incur a significant
liability for which we were not fully insured, it could have a material adverse
effect on our financial position and results of operations.  Further,
the proceeds of any such insurance may not be paid in a timely manner and may be
insufficient if such an event were to occur.





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





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


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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 may be 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.





Pursuant
to a United States Department of Transportation rule, pipeline operators are
required to develop integrity management programs for intrastate and interstate
natural gas and natural gas liquids pipelines located near high consequence
areas, where a leak or rupture could do the most harm.  The rule also
requires operators to perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could
impact a high consequence area; improve data collection, integration and
analysis; repair and remediate the pipeline as necessary; and implement
preventive and mitigating actions.  The results of these testing
programs could cause us to incur significant capital and operating expenditures
to make repairs or 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 United States Congress, especially in light of previous market
power abuse by certain companies engaged in interstate commerce.  In
response to this issue, the United States Congress, in the Energy Policy Act of
2005 (EPACT), developed requirements intended to ensure that the energy market
is not impacted by the exercise of market power or manipulative
conduct.  The FERC then adopted the Market Manipulation Rules to
implement the authority granted under EPACT.  These rules are intended
to prohibit fraud and manipulation and are subject to broad
interpretation.  EPACT also gave the FERC increased penalty authority
for violations.





Our
regulated pipelines’ transportation rates are subject to review and possible
adjustment by federal and state regulators.





Our
regulated pipelines are subject to extensive regulation by the FERC and state
regulatory agencies, which regulate most aspects of our pipeline business,
including our transportation rates.  Under the Natural Gas Act, which
is applicable to interstate natural gas pipelines, and the Interstate Commerce
Act, which is applicable to crude oil and natural gas liquids pipelines,
interstate transportation rates must be just and reasonable and not unduly
discriminatory.





Action by
the FERC or a state regulatory agency could adversely affect our pipeline
business’ ability to establish or charge rates that would cover future increases
in their costs, or even to continue to collect rates that cover current costs,
including a reasonable return.  We cannot assure unitholders that our
pipeline systems will be able to recover all of their costs through existing or
future rates.




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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 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 necessary, some of which may be material.  Additional
information is included under Item 1, Business under “Environmental and Safety
Matters” and in Note J 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 and storage capacity on our natural gas and natural
gas liquids pipelines and in our storage assets.





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





Terrorist attacks aimed at our
facilities could adversely affect our business.





Since the
September 11, 2001, terrorist attacks, the United States government has
issued warnings that energy assets, specifically the nation’s pipeline
infrastructure, may be future targets of terrorist
organizations.  These developments may subject our operations to
increased risks.  Any future terrorist attack that may target our
facilities, those of our customers and, in some cases, those of other pipelines,
could have a material adverse effect on our business.


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





We are
subject to the risk of loss resulting from nonpayment and/or nonperformance by
our customers and counterparties.  Our customers or counterparties may
experience deterioration of their financial condition as a result of changing
market conditions or financial difficulties that could impact their
creditworthiness or ability to pay us for our services.  We assess the
creditworthiness of our customers and counterparties and obtain security as we
deem appropriate.  If we fail to adequately assess the
creditworthiness of existing or future customers or counterparties,
unanticipated deterioration in their creditworthiness and any resulting
nonpayment and/or nonperformance could adversely impact our results of
operations.  In addition, if any of our customers or counterparties
file for bankruptcy protection, this could have a material negative impact on
our results of operations.





Mergers
among our customers and competitors could result in lower volumes being shipped
on our pipelines or products stored in or distributed through our terminals,
thereby reducing the amount of cash we generate.





Mergers
between our existing customers and our competitors could provide strong economic
incentives for the combined entities to utilize their existing gathering,
processing, fractionation and/or transportation systems instead of ours in those
markets where the systems compete.  As a result, we could lose some or
all of the volumes and associated revenues from these customers, and we could
experience difficulty in replacing those lost volumes and
revenues.  Because most of our operating costs are fixed, a reduction
in volumes would result not only in less revenue but also a decline in cash flow
of a similar magnitude, which would reduce our ability to pay cash distributions
to our unitholders.





A
shortage of skilled labor may make it difficult for us to maintain labor
productivity, and competitive costs could adversely affect our operations and
cash flows available for distribution to our unitholders.





Our
operations require skilled and experienced laborers with proficiency in multiple
tasks.  In recent years, a shortage of workers trained in various
skills associated with the midstream energy business has caused us to conduct
certain operations without full staff, which decreases our productivity and
increases our costs.  This shortage of trained workers is the result
of experienced workers reaching retirement age, combined with the difficulty of
attracting new laborers to the midstream energy industry.  This
shortage of skilled labor could continue over an extended period.  If
the shortage of experienced labor continues or worsens, it could have an adverse
impact on our labor productivity and costs and our ability to expand production
in the event there is an increase in the demand for our products and services,
which could adversely affect our operations and cash flows available for
distribution to our unitholders.





We
may face significant costs to comply with the regulation of greenhouse gas
emissions.





Global
warming is a significant concern for the energy industry.  Various
federal and state legislative proposals have been introduced to regulate the
emission of greenhouse gases, particularly carbon dioxide and methane, and the
United States Supreme Court has ruled that carbon dioxide is a pollutant subject
to regulation by the EPA.  In addition, there have been international
efforts seeking legally binding reductions in emissions of greenhouse
gases.





We
believe it is likely that future governmental legislation and/or regulation may
require us either to limit greenhouse gas emissions from our operations or to
purchase allowances for such emissions.  However, we cannot predict
precisely what form these future regulations will take, the stringency of the
regulations or when they will become effective.  Several bills have
been introduced in the United States Congress that would compel carbon dioxide
emission reductions.  Previously considered proposals have included,
among other things, limitations on the amount of greenhouse gases that can be
emitted (so called “caps”) together with systems of permitted emissions
allowances.  This type of system could require us to reduce emissions,
even though the technology is not currently available for efficient reduction,
or to purchase allowances for such emissions.  Emissions also could be
taxed independently of limits.





In
addition to activities on the federal level, state and regional initiatives
could also lead to the regulation of greenhouse gas emissions sooner and/or
independent of federal regulation.  These regulations could be more
stringent than any federal legislation that is adopted.





Future
legislation and/or regulation designed to reduce greenhouse gas emissions could
make some of our activities uneconomic to maintain or operate and could affect
future results of operations, cash flows or financial condition.





We
continue to monitor legislative and regulatory developments in this
area.  Although we expect the regulation of greenhouse gas emissions
may have a material impact on our operations and rates, we believe it is
premature to attempt to quantify the potential costs of the
impacts.


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We
are subject to physical and financial risks associated with climate
change.





There is
a growing belief that emissions of greenhouse gases may be linked to global
climate change.  Climate change creates physical and financial
risk.  Our customers’ energy needs vary with weather conditions,
primarily temperature and humidity.  For residential customers,
heating and cooling represent their largest energy use.  To the extent
weather conditions are affected by climate change, customers’ energy use could
increase or decrease depending on the duration and magnitude of any
changes.  Increased energy use due to weather changes may require us
to invest in more pipelines and other infrastructure to serve increased
demand.  A decrease in energy use due to weather changes may affect
our financial condition, through decreased revenues.  Extreme weather
conditions in general require more system backup, adding to costs, and can
contribute to increased system stresses, including service
interruptions.  Weather conditions outside of our service territory
could also have an impact on our revenues.  Severe weather impacts our
service territories primarily through hurricanes, thunderstorms, tornadoes and
snow or ice storms.  To the extent the frequency of extreme weather
events increases, this could increase our cost of providing
service.  We may not be able to pass on the higher costs to our
customers or recover all costs related to mitigating these physical
risks.  To the extent financial markets view climate change and
emissions of greenhouse gases as a financial risk, this could negatively affect
our ability to access capital markets or cause us to receive less favorable
terms and conditions in future financings.





We
may be subject to legislative and regulatory responses to climate change, with
which compliance could be difficult and costly.





Legislative
and regulatory responses related to climate change create financial
risk.  Increased public awareness and concern may result in more
state, regional and/or federal requirements to reduce or mitigate the emission
of greenhouse gases.  Numerous states have announced or adopted
programs to stabilize and reduce greenhouse gases and federal legislation has
been introduced in both houses of the United States Congress.  Our
pipelines, natural gas processing facilities and natural gas liquids
fractionation facilities will potentially be subject to regulation under climate
change policies introduced at either the state or federal level within the next
few years.  We may not be able to pass on the higher costs to our
customers or recover all costs related to complying with climate change
regulatory requirements, which could have a material adverse effect on our
results of operations, cash flows or financial condition.





RISKS
INHERENT IN AN INVESTMENT IN US





ONEOK
selling substantial amounts of common units could reduce the market price of our
common units.





ONEOK and
its affiliates own all of the Class B units, 5,900,000 common units and the
entire 2 percent general partner interest in us, which together constitutes a
47.7 percent 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.  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.





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


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distributions
payable on the Class B limited partner units would increase to 123.5 percent of
the distributions payable with respect to the common units, and distributions
payable upon liquidation of the Class B limited partner units would increase to
123.5 percent of the distributions payable with respect to the common
units.





Our unitholders have limited voting
rights and are not entitled to elect our general partner’s directors, which
could lower the trading price of our common units. In addition, even if
unitholders are dissatisfied, they cannot easily remove our general
partner.





Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our
business.  Unitholders have no right to elect our general partner or
its directors on an annual or other continuing basis.  The Board of
Directors of our general partner, including the independent directors, is chosen
by the owners of the general partner and not by the unitholders.





Furthermore,
if unitholders are dissatisfied with the performance of our general partner, it
may be difficult to remove ONEOK Partners GP or its officers or
directors.  ONEOK Partners GP may not be removed except upon the vote
of the holders of at least 66-2/3 percent of our outstanding units voting
together as a single class (excluding units held by ONEOK Partners GP and its
affiliates).  As a result of this provision, the trading price of our
common units may be lower than other forms of equity ownership because of the
absence or reduction of a takeover premium in the trading price.





We
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, ONEOK Partners GP and third-party providers with
which they contract, together with our limited ability to control certain costs,
could harm our business and results of operations.





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





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


·
            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, or not
      inconsistent with, 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


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





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





The
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 47.7 percent aggregate
equity interest in us.  Our Partnership Agreement limits any fiduciary
duties owed by our general partner and ONEOK to those duties that are
specifically stated in our Partnership Agreement.  Although ONEOK,
through the Board of Directors of our general partner, has an obligation to
manage us in a manner that is in, or not inconsistent with, our best interests,
the Board of Directors of ONEOK has a fiduciary duty to manage our general
partner in a manner beneficial to ONEOK.  One management member of the
Board of Directors of our general partner is also the only management 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
determine that the transaction is “fair and reasonable” to us, without the
agreement of any other party, including the Audit Committee.  In that
regard, our general partner may favor its own interests and the interests of its
affiliates over the interests of our unitholders, as long as it does not take
action that conflicts with our Partnership Agreement.  These conflicts
include, among others, the following situations:


·
            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, which right may be assigned or transferred to, among others, us or
      affiliates of the general partner, if the general partner and its
      affiliates own 80 percent or more of the common units;
  and


·
            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.




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





Our
general partner may transfer all, or any part of, its general partner interest
to a third party without the consent of the unitholders.  The members,
shareholders or unitholders, as the case may be, of our new general partner may
then be in a position to replace all or a portion of the directors of our
general partner with their own choices and to possibly control the decisions
made by the Board of Directors of our general partner.





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
cannot provide assurance that any of our current ratings will remain in effect
for any given period of time or that a rating will not be lowered or withdrawn
entirely by a rating agency if, in its judgment, circumstances in the future so
warrant.  Specifically, if Moody’s or S&P were to downgrade our
long-term rating, particularly below investment grade, our borrowing costs would
increase, which would adversely affect our financial results, and our potential
pool of investors and funding sources could decrease.  If Moody's or
S&P were to downgrade our long-term ratings below investment grade, we
would, under certain circumstances, be required to offer to repurchase certain
of our senior notes.  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.





We
do not have the same flexibility as other types of organizations to accumulate
cash and equity to protect against illiquidity in the future.





Unlike a
corporation, our Partnership Agreement requires us to make quarterly
distributions to our unitholders of all available cash reduced by any amounts of
reserves for commitments and contingencies, including capital and operating
costs and debt- service requirements, all of which are
significant.  The value of our units and other limited partner
interests may decrease in correlation with decreases in the amount we distribute
per unit.  Accordingly, if we experience a liquidity problem in the
future, we may not be able to issue more equity to recapitalize.





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
other obligations.





As of
December 31, 2008, we had total indebtedness of approximately $3.5
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;




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·
            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,
      and general 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.





We are
not prohibited under the indentures governing our senior notes from incurring
additional indebtedness, but our debt agreements do subject us to certain
operational limitations summarized in the next paragraph. Our incurrence of
significant additional indebtedness would exacerbate the negative consequences
mentioned above and could adversely affect our ability to repay our notes and
other indebtedness.





Our debt
agreements contain provisions that restrict our ability to finance future
operations or capital needs or to expand or pursue our business
activities.  For example, certain of these agreements contain
provisions that, among other things, limit our ability to make loans or
investments, make material changes to the nature of our business, merge,
consolidate or engage in asset sales, or grant liens or make negative
pledges.  Certain of these agreements also require us to maintain
certain financial ratios, which limits the amount of additional indebtedness we
can incur.  These restrictions could result in higher costs of
borrowing and impair our ability to generate additional
cash.   Future financing agreements we may enter into may contain
similar or more restrictive covenants.





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





We
and the Intermediate Partnership 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 other
investments.  As a result, our ability to make quarterly distributions
and required payments on our indebtedness depends on the performance of our
subsidiaries and their ability to distribute funds to us.  The ability
of our subsidiaries to make distributions to us may be restricted by, among
other things, credit facilities, applicable state partnership laws, and other
laws and regulations, including FERC policies.  If we are unable to
obtain the funds necessary to make quarterly distributions or required payments
on our indebtedness, we may be required to adopt one or more alternatives, such
as refinancing the indebtedness or seeking alternative financing sources to fund
the quarterly distributions and indebtedness payments.





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





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


·
            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.





Notwithstanding
the foregoing, the issuance of equity securities ranking senior to the common
units requires approval of a majority of the outstanding common
units.





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 80 percent or more of the common
units, our general partner will have the right, but not the obligation, which it
may assign to any of its affiliates or to us, to acquire all, but not less than
all, of the common units held by unaffiliated persons at a price not less than
their then-current market price.  As a result, unitholders may be
required to sell their common units at an undesirable time or price and may not
receive any return on their investment.  Unitholders may also incur a
tax liability upon the sale of their units.  Our general partner is
not obligated to obtain a fairness opinion regarding the value of the common
units to be repurchased by it upon exercise of the limited call


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





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, other than our corporate subsidiaries, 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.





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.





Because
of widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation.  For
example, beginning in 2008, we were required to pay the revised Texas franchise
tax at a maximum effective rate of 0.7 percent of our gross revenue that is
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.





The
tax treatment of our structure could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a
retroactive basis.





The
federal income tax treatment of us and common unitholders depends in some
instances on determinations of fact and interpretations of complex provisions of
federal income tax law.  The federal income tax rules are constantly
under review by persons involved in the legislative process, the IRS and the
United States Treasury Department (Treasury), frequently resulting in revised
interpretations of established concepts, statutory changes, revisions to
Treasury regulations and other modifications and interpretations. The IRS pays
close attention to the proper application of tax laws to
partnerships.  The




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present
federal income tax treatment of us and/or an investment in our common units may
be modified by administrative,legislative or judicial interpretation at any
time.  For example, in response to certain recent developments,
members of the United States Congress are considering substantive changes to the
definition of qualifying income under the Internal Revenue Code Section 7704(d)
and the treatment of certain types of income earned from profits interests in
the partnerships.  Any modification to the federal income tax laws and
interpretations thereof may or may not be applied retroactively and could make
it more difficult or impossible for us to meet the exception to be treated for
federal income tax purposes as a partnership that is not taxable as a
corporation (referred to as the “Qualifying Income Exception”), affect or cause
us to change our business activities, affect the tax consequences for common
unitholders of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our common
units.  We are unable to predict whether any of these or other changes
or proposals will ultimately be enacted.  Any such changes could
negatively impact the value of an investment in our common units and the amount
of cash available for distribution to our unitholders.





An
IRS contest of the federal income tax positions we take may adversely impact the
market for our common units, and the costs of any 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 will be required to pay taxes on the unitholder’s share of our
taxable 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.





Unitholders
may have negative tax consequences if we default on our debt or sell
assets.





If we
default on any of our debt, the lenders will have the right to sue us for
non-payment. Such an action could cause negative tax consequences for
unitholders through the realization of taxable income by unitholders without a
corresponding cash distribution.  Likewise, if we were to dispose of
assets and realize a taxable gain while there is substantial debt outstanding
and proceeds of the sale were applied to the debt, unitholders could have
increased taxable income without a corresponding cash distribution.





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 and 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 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
and non-U.S. persons, raises issues unique to them.  For example,
virtually all of our income allocated to unitholders who are organizations
exempt from federal income tax, including individual retirement accounts and
other retirement plans, may be taxable to them as “unrelated


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business
taxable income.”  Distributions to non-U.S. persons may be subject to
U.S. withholding taxes.  Non-U.S. persons will be required to file
U.S. federal income tax returns and pay tax on their share of our taxable
income.





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





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





We
may be required to change the allocation of items of income, gain, loss and
deduction among our unitholders.





We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our units
as of the close of business on the last day of the preceding month, instead of
on the basis of the date a particular unit is transferred.  The use of
this proration method may not be permitted under existing Treasury
regulations.  If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.





Unitholders
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.





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, which may
result in us filing two tax returns for one fiscal year.





Our
termination could also result in a deferral of depreciation deductions allowable
in computing taxable income.  Our termination currently would not
affect our classification as a partnership for federal income tax purposes,
instead, we would be treated as a new partnership, we must make new tax
elections, and we could be subject to penalties if we were unable to determine
that the termination had occurred.





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 common 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)


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adjustment
attributable to our tangible and intangible assets, and allocations of income,
gain, loss and deduction between the general partner and certain of our
unitholders.





A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our
unitholders.  It also could affect the amount of gain from our
unitholders’ sale of common units and could have a negative impact on the value
of the common units or result in audit adjustments to our unitholders’ tax
returns without the benefit of additional deductions.





A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so, the unitholder
would no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or loss from the
disposition.





Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, the unitholder
may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may
recognize gain or loss from such disposition.  Moreover, during the period
of the loan to the short seller, any of our income, gain, loss or deduction with
respect to those units may not be reportable by the unitholder, and any cash
distributions received by the unitholder as to those units could be fully
taxable as ordinary income.  Unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a short seller
are urged to modify any applicable brokerage account agreements to prohibit
their brokers from borrowing their units.




ITEM
1B.                            UNRESOLVED
STAFF COMMENTS




Not
applicable.





ITEM
2.                           PROPERTIES





Natural
Gas Gathering and Processing





Property - Our Natural Gas
Gathering and Processing segment owns the following assets:


·
            approximately
      10,100 miles and 4,500 miles of natural gas gathering pipelines in the
      Mid-Continent and Rocky Mountain regions,
  respectively;


·
            nine
      active natural gas processing plants, with approximately 645 MMcf/d of
      processing capacity in the Mid-Continent region, and four active natural
      gas processing plants, with approximately 80 MMcf/d of processing capacity
      in the Rocky Mountain region; and


·
            approximately
      18 MBbl/d of natural gas liquids fractionation capacity at various natural
      gas processing plants in the Mid-Continent and Rocky Mountain
      regions.





On
January 1, 2007, the Bushton Plant was temporarily idled as a result of a
decline in natural gas volumes available for natural gas processing at this
straddle plant.  Volumes declined due to natural field declines and as
a result of contract terminations, as advances in technology made it more cost
efficient to process natural gas at other facilities.  We have
contracted for all of the capacity of the plant from ONEOK.





Utilization - The utilization
rate for our natural gas processing plants was approximately 71 percent for
2008.




Natural
Gas Pipelines




Property- Our Natural Gas
Pipelines segment owns the following assets:


·
            approximately
      1,320 miles of FERC-regulated interstate natural gas pipelines with
      approximately 2.5 Bcf/d of peak transportation
  capacity;


·
            approximately
      5,560 miles of intrastate natural gas gathering and state-regulated
      intrastate transmission pipelines with peak transportation capacity of
      approximately 3.3 Bcf/d; and


·
            approximately
      51.6 Bcf of total active working natural gas storage
    capacity.





Our
storage includes five underground natural gas storage facilities in Oklahoma,
three underground natural gas storage facilities in Kansas and three underground
natural gas storage facilities in Texas.  One of our natural gas
storage facilities outside of Hutchinson, Kansas, has been idle since 2001,
following natural gas explosions and eruptions of natural gas geysers.  We
began injecting brine into the facility in the first quarter of 2007 in order to
ensure the long-term integrity of the


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idled
facility.  We expect to complete the injection process by the end of
2011.  Monitoring of the facility and review of the data for the
geoengineering studies are ongoing, in compliance with a KDHE order while we
evaluate the alternatives for the facility.  Following the testing of the
gathered data, we expect that the facility will be returned to storage service,
although most likely for a product other than natural gas.  The return to
service will require KDHE approval.  It is possible, however, that testing
could reveal that it is not safe to return the facility to service or that the
KDHE will not grant the required permits to resume service.





Utilization- During 2008, our
natural gas pipelines were approximately 86 percent subscribed, and our storage
facilities were fully subscribed.





Natural
Gas Liquids Gathering and Fractionation





Property-Our Natural Gas Liquids
Gathering and Fractionation segment owns the following assets:


·
            approximately
      2,011 miles of natural gas liquids gathering pipelines with peak capacity
      of approximately 247 MBbl/d;


·
            approximately
      163 miles of natural gas liquids distribution pipelines with peak
      transportation capacity of approximately 66
  MBbl/d;


·
            two
      natural gas liquids fractionators with operating capacity of approximately
      260 MBbl/d;


·
            80
      percent ownership interest in one natural gas liquids fractionator with
      operating capacity of approximately 160
MBbl/d;


·
            interest
      in one natural gas liquids fractionator with proportional operating
      capacity of approximately 11
MBbl/d;


·
            one
      9 MBbl/d isomerization unit; and


·
            six
      NGL storage facilities in Oklahoma, Kansas and Texas with operating
      storage capacity of approximately 23.2
MMBbl.





In
addition, we lease four NGL storage facilities in Oklahoma, Kansas and Texas
with operating storage capacity of approximately 3.2 MMBbl.  We also
own and lease assets through an affiliate at the Bushton facility in Kansas,
which includes 150 MBbl/d of fractionation capacity.





During
2007 and 2008, we added new natural gas liquids fractionation facilities at the
Bushton location, in conjunction with other changes that were made to the NGL
fractionation capabilities of the existing plant.  Although the
Bushton Plant remains idled, we currently have 150 MBbl/d of active NGL
fractionation capacity as a result of combining the previously existing
fractionation equipment with the new fractionation facilities.  We
resumed fractionating NGLs at the facilities in the second half of
2008.





Utilization-The utilization rate for
our natural gas liquids gathering pipelines was approximately 73 percent for
2008.  Our average contracted storage volume was approximately 74
percent of storage capacity for 2008.  The utilization rate for our
natural gas liquids fractionators was approximately 87 percent for
2008.  Our fractionation utilization rate reflects approximate
proportional capacity associated with ownership interests noted above and
partial service for our Bushton facility, which was placed in service during the
second half of 2008.




Natural
Gas Liquids Pipelines




Property- Our Natural Gas
Liquids Pipelines segment owns the following assets:


·
            approximately
      1,480 miles of FERC-regulated natural gas liquids gathering pipelines with
      peak capacity of approximately 203
MBbl/d;


·
            approximately
      3,480 miles of FERC-regulated natural gas liquids and refined petroleum
      products distribution pipelines with peak transportation capacity of 691
      MBbl/d;


·
            eight
      NGL product terminals in Missouri, Nebraska, Iowa and Illinois;
      and


·
            above-
      and below-ground storage facilities in Iowa, Illinois, Nebraska and Kansas
      with 978 MBbl operating capacity.





Utilization - The utilization
rate for our FERC-regulated natural gas liquids gathering pipelines was
approximately 55 percent for 2008.  Utilization rate for our natural
gas liquids distribution pipelines was approximately 49 percent for
2008.  We calculated utilization on our assets using a
weighted-average approach, adjusting for the in-service dates of our assets
placed in service during 2008.


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Other





Our Other
segment includes Black Mesa Pipeline, which we started decommissioning in the
second quarter of 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, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK
WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch
Hydrocarbon, LP), 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, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK
WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch
Hydrocarbon, LP), 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.





Mont
Belvieu Emissions, Texas
Commission on Environmental Quality-We are in discussions
with the Texas Commission on Environmental Quality (TCEQ) staff regarding air
emissions from a heat exchanger at our Mont Belvieu fractionator, which may have
exceeded the emissions allowed under our air permit.  We discovered
the possibility of excessive air emissions in May 2008.  The TCEQ has
not issued a notice of enforcement relating to the emissions under this
permit.  Although no assurances can be given, we do not believe that
any penalties associated with any alleged violations will have a material
adverse effect on our financial position, results of operations, or net cash
flows.





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
      Ended
                  
                  
                  Year
      EndedDecember
      31, 2008
                  
                  
                  December
      31, 2007High
                  
                  
                  Low
                  
                  
                  High
                  
                  
                  LowFirst
      Quarter
                  
                  $
                  63.89
                  
                  
                  $
                  54.58
                  
                  
                  $
                  67.80
                  
                  
                  $
                  62.62Second
      Quarter
                  
                  $
                  64.01
                  
                  
                  $
                  55.90
                  
                  
                  $
                  72.42
                  
                  
                  $
                  66.82Third
      Quarter
                  
                  $
                  60.05
                  
                  
                  $
                  50.32
                  
                  
                  $
                  70.70
                  
                  
                  $
                  58.20Fourth
      Quarter
                  
                  $
                  55.88
                  
                  
                  $
                  39.25
                  
                  
                  $
                  65.41
                  
                  
                  $
                  59.00





At
February 18, 2009, there were 834holders of record of our 54,426,087 outstanding common
units.  ONEOK and its affiliates own all of the Class B units,
5,900,000 common units and the entire 2 percent general partner interest in us,
which together constitutes a 47.7 percent ownership interest in us.





CASH
DISTRIBUTIONS





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





Years
      Ended December 31,2008
                  
                  
                  2007First
      Quarter
                  
                  $
                  1.025
                  
                  
                  $
                  0.980Second
      Quarter
                  
                  $
                  1.040
                  
                  
                  $
                  0.990Third
      Quarter
                  
                  $
                  1.060
                  
                  
                  $
                  1.000Fourth
      Quarter
                  
                  $
                  1.080
                  
                  
                  $
                  1.010




In
January 2009, we declared a cash distribution of $1.08 per unit ($4.32 per unit
on an annualized basis) for the fourth quarter of 2008, which was paid on
February 13, 2009, to unitholders of record as of January 30, 2009.





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 cash receipts less adjustments for cash disbursements and net
changes to reserves.  Available cash will generally be distributed to
our general partner and limited partners according to their partnership
percentages of 2 percent and 98 percent, respectively.  Our general
partner’s percentage interest in quarterly distributions is increased after
certain specified target levels are met.  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 $453.0 million for
2008 and $384.6 million for 2007, which included an incentive distribution to
our general partner of $69.9 million for 2008 and $47.1 million for
2007.  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 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.  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, 2003, and ending on December 31, 2008.  The graph assumes
a $100 investment in our common units and in each of the indices at the
beginning of the period and a reinvestment of distributions/dividends paid on
such investments throughout the period.




Value
      of $100 Investment Assuming Reinvestment of
      Distributions/DividendsAt
      December 31, 2003, and at the End of Every Year Through December 31,
      2008Among
      ONEOK Partners LP, the S&P 500 Index and the Alerian MLP
      Index








Cumulative
      Total ReturnYears
      Ending December 31,2003
                      
                      
                      2004
                      
                      
                      2005
                      
                      
                      2006
                      
                      
                      2007
                      
                      
                      2008ONEOK
      Partners, L.P.
                      
                      $
                      100.00
                      
                      
                      $
                      132.53
                      
                      
                      $
                      123.45
                      
                      
                      $
                      199.73
                      
                      
                      $
                      205.01
                      
                      
                      $
                      164.26S&P
      500 Index
                      
                      $
                      100.00
                      
                      
                      $
                      110.88
                      
                      
                      $
                      116.32
                      
                      
                      $
                      134.69
                      
                      
                      $
                      142.09
                      
                      
                      $
                      89.52Alerian
      MLP Index (a)
                      
                      $
                      100.00
                      
                      
                      $
                      116.67
                      
                      
                      $
                      124.04
                      
                      
                      $
                      156.07
                      
                      
                      $
                      175.88
                      
                      
                      $
                      111.12(a)
      - The Alerian MLP Index measures the composite performance of the 50 most
      prominent energy master limited partnerships.




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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 31,2008
                    
                    
                    2007
                    
                    
                    2006
                    
                    
                    2005
                    
                    
                    2004(In
      thousands of dollars, except per unit data)Revenues
                    
                    $
                    7,720,206
                    
                    
                    $
                    5,831,558
                    
                    
                    $
                    4,738,248
                    
                    
                    $
                    703,944
                    
                    
                    $
                    590,383Income
      from continuing operations
                    
                    $
                    625,616
                    
                    
                    $
                    407,747
                    
                    
                    $
                    445,186
                    
                    
                    $
                    146,507
                    
                    
                    $
                    140,921Net
      income
                    
                    $
                    625,616
                    
                    
                    $
                    407,747
                    
                    
                    $
                    445,186
                    
                    
                    $
                    147,013
                    
                    
                    $
                    144,720Total
      assets
                    
                    $
                    7,254,272
                    
                    
                    $
                    6,112,065
                    
                    
                    $
                    4,921,717
                    
                    
                    $
                    2,527,766
                    
                    
                    $
                    2,514,690Long-term
      debt, including current maturities
                    
                    $
                    2,601,440
                    
                    
                    $
                    2,617,326
                    
                    
                    $
                    2,031,529
                    
                    
                    $
                    1,123,971
                    
                    
                    $
                    1,139,358Per
      unit income from continuing operations
                    
                    $
                    6.01
                    
                    
                    $
                    4.21
                    
                    
                    $
                    5.01
                    
                    
                    $
                    2.92
                    
                    
                    $
                    2.81Per
      unit net income
                    
                    $
                    6.01
                    
                    
                    $
                    4.21
                    
                    
                    $
                    5.01
                    
                    
                    $
                    2.93
                    
                    
                    $
                    2.89Distributions
      per common unit (a)
                    
                    $
                    4.205
                    
                    
                    $
                    3.98
                    
                    
                    $
                    3.60
                    
                    
                    $
                    3.20
                    
                    
                    $
                    3.20(a)
      - Class B unitholders received the same distribution as common
      unitholders.




Financial
data for 2008, 2007 and 2006 is not directly comparable with 2005 and 2004 due
to the significance of the April 2006 ONEOK Transactions.  See
discussion of acquisitions and dispositions beginning on page 37 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 this past
year.  Please refer to the “Liquidity and Capital Resources,” “Capital
Projects,” and “Financial Results and Operating Information” sections of
Management’s Discussion and Analysis of Financial Condition and Results of
Operation and our Consolidated Financial Statements for additional
information.





Equity Issuance - In March
2008, we completed a public offering of 2.5 million common units at $58.10 per
common unit, generating net proceeds of approximately $140.4 million after
deducting underwriting discounts but before offering expenses.  In
addition, we sold 5.4 million common units to ONEOK in a private placement,
generating proceeds of approximately $303.2 million.  In conjunction
with the public offering of common units and the private placement, ONEOK
Partners GP contributed $9.4 million in order to maintain its 2 percent general
partner interest in us.





In April
2008, we sold an additional 128,873 common units at $58.10 per common unit to
the underwriters of the public offering upon the partial exercise of their
option to purchase additional common units to cover
over-allotments.  We received net proceeds of approximately $7.2
million from the sale of the common units after deducting underwriting discounts
but before offering expenses.  In conjunction with the partial
exercise by the underwriters, ONEOK Partners GP contributed $0.2 million in
order to maintain its 2 percent general partner interest in us.  As a
result of these transactions, ONEOK now holds a 47.7 percent aggregate equity
interest in us.





We used a
portion of the proceeds from the sale of common units and the general partner
contributions to repay borrowings under our amended and restated revolving
credit agreement dated March 30, 2007 (Partnership Credit
Agreement).





Cash Distributions - During
2008, we paid cash distributions totaling $4.205 per unit, an increase of
approximately 6 percent over the $3.98 per unit paid during 2007.  On
January 13, 2009, we declared a cash distribution of $1.08 per unit ($4.32 per
unit on an annualized basis), an increase of approximately 5 percent over the
$1.025 declared in January 2008.





Capital Projects - The
following projects were placed in-service during 2008:


·
            January
      - Midwestern Gas Transmission’s eastern extension
  pipeline;


·
            July
      - final phase of Fort Union Gas Gathering expansion
    project;


·
            September
      - Woodford Shale natural gas liquids pipeline
  extension;


·
            October
      - Bushton fractionation
expansion;


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·
            November
      - Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas;
      and


·
            December
      - partial operations of the Guardian Pipeline extension with interruptible
      service from Ixonia, Wisconsin, to Green Bay,
  Wisconsin.





Operating Results - Net income
per unit increased to $6.01 in 2008, compared with $4.21 in 2007.  The
increase in net income per unit in 2008 is primarily due to the
following:


·
            wider
      NGL product price differentials, increased NGL gathering and fractionation
      volumes and certain operational measurement gains, primarily at NGL
      storage caverns, in our Natural Gas Liquids Gathering and Fractionation
      segment;


·
            higher
      realized commodity prices, improved contractual terms and higher volumes
      sold and processed in our Natural Gas Gathering and Processing
      segment;


·
            incremental
      operating income in our Natural Gas Liquids Pipelines segment from the
      assets acquired from Kinder Morgan in October 2007;
  and


·
            increased
      transportation and storage margins as a result of the impact of higher
      natural gas prices on retained fuel and new and renegotiated storage
      contracts in our Natural Gas Pipelines
segment.




During
September 2008, our Natural Gas Gathering and Processing segment, Natural Gas
Liquids Gathering and Fractionation segment, and Natural Gas Liquids Pipelines
segment experienced disruptions related to Hurricane Ike.  Without
these disruptions, we estimate our net margin of $1.1 billion for 2008 would
have been approximately $7.8 million higher.





Outlook
for 2009





We expect
continued deteriorating economic conditions in 2009, with downward pressures,
relative to 2008, on commodity prices for natural gas, NGLs and crude oil. 
We anticipate that lower commodity prices will result in reduced drilling
activity and economic conditions will reduce petrochemical demand.  We
also expect continued volatility and disruption in the financial markets, which
could result in increased cost of capital.  We expect depressed commodity
prices and tighter capital markets to also result in the sale or consolidation
of underperforming assets in the industry, which may present opportunities for
us.





We intend
to pursue growth in our natural gas businesses through well-connects and
contract renegotiations and through expansions and extensions of our existing
systems and plants.  For our natural gas liquids businesses, we intend to
continue to focus on adding new supply connections, optimizing existing assets,
as well as completing our growth projects currently under construction. 
Capital expenditures in 2009 are expected to be significantly lower than in 2008
when we spent approximately $1.3 billion.  We plan to spend
approximately $425 million on capital expenditures in 2009, of which
approximately $355 million is for growth projects.  We also plan to
pursue strategic acquisitions.





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 products and refined petroleum products.  The FERC-regulated
system spans 1,624 miles and has a capacity to transport up to 134
MBbl/d.  The transaction also included 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 Heartland, which consists primarily of one refined
petroleum products terminal and pipelines with access to two other refined
petroleum product terminals.  Our investment in Heartland is accounted
for under the equity method of accounting.  Financing for this
transaction came from a portion of the proceeds of our September 2007 issuance
of $600 million 6.85 percent Senior Notes due 2037 (the 2037
Notes).  See Note I of the Notes to Consolidated Financial Statements
in this Annual Report on Form 10-K for a discussion of the 2037
Notes.  The working capital settlement was finalized in April 2008,
with no material adjustments.  These assets are included in our
Natural Gas Liquids Pipelines segment.





Overland Pass Pipeline Company- See “Capital Projects” for discussion of Overland Pass Pipeline
Company.





The ONEOK Transactions- In
April 2006, we completed the acquisition of 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.


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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.  After this acquisition, ONEOK owned approximately 37.0
million of our common units, which, when combined with its general partner
interest, increased its total interest in us to approximately 45.7 percent at
the date of acquisition.  We used $1.05 billion drawn under a $1.1
billion, 364-day credit agreement, 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 connection with 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.  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 connection with the ONEOK
Transactions, in April 2006, we completed the sale of a 20 percent partnership
interest in Northern Border Pipeline to TC PipeLines for approximately $297
million to help finance the acquisition of the ONEOK Energy
Assets.  We recorded a gain on the sale of approximately $113.9
million in the second quarter of 2006.  We and TC PipeLines each now
own a 50 percent interest in Northern Border Pipeline, and an affiliate of
TransCanada became the operator of the pipeline in April
2007.  Effective January 1, 2006, our interest in Northern Border
Pipeline is accounted for as an investment under the equity method in our
Natural Gas Pipelines segment.





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





CAPITAL
PROJECTS





Woodford Shale Natural Gas Liquids
Pipeline Extension- The 78-mile natural gas liquids gathering pipeline
connecting two natural gas processing plants, operated by Devon Energy
Corporation and Antero Resources Corporation, was placed into service in
September 2008.  The cost of the project was approximately $36
million, excluding AFUDC.  These two plants have the capacity to
produce approximately 25 MBbl/d of unfractionated NGLs.  The natural gas
liquids production is gathered by our existing Mid-Continent natural gas liquids
gathering pipelines.  Upon completion of the Arbuckle Pipeline
project, the Woodford Shale natural gas liquids production is expected to be
transported through the Arbuckle Pipeline to our Mont Belvieu, Texas,
fractionation facility.  This project is 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 The Williams Companies,
Inc. (Williams) to form a joint venture called Overland Pass Pipeline
Company.  In November 2008, Overland Pass Pipeline Company completed
construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to
the Mid-Continent natural gas liquids market center in Conway,
Kansas.  The Overland Pass Pipeline is designed to transport
approximately 110 MBbl/d of unfractionated NGLs and can be increased to
approximately 255 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.  Initially, as the 99 percent owner of the joint
venture, we managed the construction project and advanced all costs associated
with construction.  We are currently operating the
pipeline.  On or before November 17, 2010, Williams will have the
option to increase its ownership up to 50 percent, with the purchase price being
determined in accordance with the joint venture’s operating
agreement.  If Williams exercises its option to increase its ownership
to the full 50 percent, Williams would have the option to become
operator.  The pipeline project cost was approximately $575 million,
excluding AFUDC.




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As part
of a long-term agreement, Williams dedicated its NGL production from two of its
natural gas processing plants in Wyoming, estimated to be approximately 60
MBbl/d, to the Overland Pass Pipeline.  We will provide downstream





We also
invested approximately $239 million, excluding AFUDC, to expand our existing
fractionation and storage capabilities and to increase the capacity of our
natural gas liquids distribution pipelines.  Part of this expansion
included adding new fractionation facilities at our Bushton location, which
increased the total fractionation capacity at the Bushton facility from 80
MBbl/d to 150 MBbl/d.  The addition of the new facilities and the
upgrade to the existing fractionator was completed in October
2008.  Additionally, portions of our natural gas liquids distribution
pipeline upgrades were completed in the second and third quarters of
2008.  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, with
estimated volumes totaling approximately 30 MBbl/d, to be transported by the
lateral pipeline.  We continue to negotiate with other producers for
supply commitments.  In October 2008, this project received the
approval of various state and federal regulatory authorities, allowing
construction to commence.  Construction began during the fourth
quarter of 2008 and is expected to be completed during the third quarter of
2009.  The project is currently estimated to cost in the range of $110
million to $140 million, excluding AFUDC.  This project is in our
Natural Gas Liquids Pipelines segment.





D-J Basin Lateral Pipeline -
In September 2008, we announced plans to construct a 125-mile natural gas
liquids lateral pipeline from the Denver-Julesburg Basin in northeastern
Colorado to the Overland Pass Pipeline, with capacity to transport as much as 55
MBbl/d of unfractionated NGLs.  The project is currently estimated to
cost in the range of $70 million to $80 million, excluding AFUDC.  We
have supply commitments for up to 33 MBbl/d of unfractionated NGLs with
potential for an additional 10 MBbl/d of supply from new drilling and plant
upgrades in the next two years.  The pipeline is currently under
construction and is expected to be fully completed during the first quarter of
2009.  This project is in our Natural Gas Liquids Pipelines
segment.





Arbuckle 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.  The Arbuckle
Pipeline will have the capacity to transport 160 MBbl/d of unfractionated NGLs,
expandable to 210 MBbl/d with additional pump facilities, and will connect our
existing Mid-Continent infrastructure with our fractionation facility in Mont
Belvieu, Texas, and other Gulf Coast region fractionators.  We have
supply commitments from producers that we expect will be sufficient to fill the
210 MBbl/d capacity level over the next three to five
years.  Construction on the pipeline has been under way since the
third quarter of 2008.  Much of the Oklahoma and north Texas portions
are either complete or nearing completion.  However, right-of-way
acquisition has been challenging, time consuming and expensive, which could
affect the completion schedule and final cost of the project.  Many of
Arbuckle Pipeline’s remaining right-of-way tracts are being acquired through a
condemnation process, which adds to the cost and time to construct the pipeline.
The demand for surface easements has increased dramatically in Texas and
Oklahoma in the last 12 to 18 months because of increased oil and natural gas
exploration and production activities, as well as pipeline
construction.  Because of the delays associated with right-of-way
acquisition, we anticipate construction on the south end of the project will be
more difficult and expensive due to wet low-lying areas and potential for spring
rains.  Accordingly, we expect the project to be
operational in the second quarter of 2009.  Based on the
increased costs and delays associated with right-of-way acquisition and
potential weather impacts, our project costs could increase 10 percent to 15
percent above the range of $340 million to $360 million, excluding AFUDC, as
previously reported.  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, currently estimated to cost in
the range of $40 million to $45 million, excluding AFUDC.  Our
estimated project costs increased from $30 million, primarily as a result of
higher contract labor and equipment costs.  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 MBbl/d.  The construction on the
expansion project is expected to be complete in the first quarter of
2009.  This project is in our Natural Gas Gathering and Processing
segment.




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Fort Union Gas Gathering
Expansion - In January 2007, Fort Union Gas Gathering announced plans to
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 occurred in two
phases and cost approximately $121





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 capacity to transport 537 MMcf/d of
natural gas north from Ixonia, Wisconsin, to the Green Bay, Wisconsin
area.  The project is supported by 15-year shipper commitments with We
Energies and Wisconsin Public Service Corporation, and the capacity has been
fully subscribed.  The project is currently estimated to cost in the
range of $277 million to $305 million, excluding AFUDC.  Our estimated
project costs increased from our initial estimate of $241 million in 2006, which
excluded AFUDC, primarily due to weather delays, equipment delivery delays,
construction in environmentally sensitive areas, rocky terrain and escalating
costs associated with crop damage and condemnation costs.  We received
the notice to proceed from the FERC in May 2008.  On December 22,
2008, the FERC issued a letter order granting Guardian Pipeline’s request for an
extension of time for a phased in-service.  On December 29, 2008, the FERC
issued a letter order granting Guardian Pipeline’s request to commence service.
 On December 31, 2008, the pipeline and seven meter stations were placed
into service with the ability to transport natural gas on a limited basis. 
Construction on one compressor station is complete, and construction on a second
compressor station is near completion.  The project is expected to be fully
in service in the first quarter of 2009.  This project is in our
Natural Gas Pipelines segment.




IMPACT
OF NEW ACCOUNTING STANDARDS




Information
about the impact of the following new accounting standards is included in Note A
of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K:


·
            Statement
      157, “Fair Value Measurements,” and related FASB Staff Position (FSP)
      157-2, “Effective Date of FASB Statement No. 157,” and FSP 157-3,
      “Determining the Fair Value of a Financial Asset When the Market for That
      Asset Is Not Active;”


·
            Statement
      159, “The Fair Value Option for Financial Assets and Financial
      Liabilities;”


·
            FSP
      FIN 39-1, “Amendment of FASB Interpretation No.
  39;”


·
            Statement
      141R, “Business Combinations;”


·
            Statement
      160, “Noncontrolling Interests in Consolidated Financial Statements - an
      amendment of ARB No. 51;”


·
            EITF
      08-6, “Equity Method Investment Accounting
  Considerations;”


·
            Statement
      161, “Disclosures about Derivative Instruments and Hedging Activities - an
      amendment to FASB Statement No. 133;”
and


·
            EITF
      07-4, “Application of the Two-Class Method under FASB Statement No. 128 to
      Master Limited Partnerships.”




CRITICAL
ACCOUNTING ESTIMATES




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





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




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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





We assess
our goodwill for impairment at least annually, based on Statement 142, “Goodwill
and Other Intangible Assets.”  There were no impairment charges
resulting from our July 1, 2008, impairment test.  As a result of
recent events in the financial markets and current economic conditions, we
performed a review and determined that interim testing of goodwill as of
December 31, 2008, was not necessary.  As part of our impairment test,
an initial assessment is made by comparing the fair value of a reporting unit
with its book value, including goodwill.  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 reporting unit from the fair value
determined in step one of the assessment.  If the carrying value of
the goodwill exceeds the implied fair value of the goodwill, we will record an
impairment charge.





We use
two generally accepted valuation approaches, an income approach and a market
approach, to estimate the fair value of a reporting unit.  Under the
income approach, we use anticipated cash flows over a three-year period plus a
terminal value and discount these amounts to their present-value using
appropriate rates of return.  Under the market approach, we apply
multiples to forecasted EBITDA amounts.  The multiples used are
consistent with historical asset transactions, and the EBITDA amounts are based
on average EBITDA for a reporting unit over a three-year forecasted
period.  At December 31, 2008, we had $396.7 million of goodwill
recorded on our Consolidated Balance Sheet as shown below.


(Thousands
      of dollars)Natural
      Gas Gathering and Processing
                                
                                $
                                90,037Natural
      Gas Pipelines
                                
                                
                                131,115Natural
      Gas Liquids Gathering and Fractionation
                                
                                
                                175,566Total
      goodwill
                                
                                $
                                396,718
 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 $279.8 million of intangible assets
recorded on our Consolidated Balance Sheet as of December 31,
2008.


(Thousands
      of dollars)Natural
      Gas Liquids Gathering and Fractionation
                          
                          $
                          266,451Natural
      Gas Liquids Pipelines
                          
                          
                          13,367Total
      intangible assets
                          
                          $
                          279,818


Our
impairment tests require the use of assumptions and estimates.  If
actual results are not consistent with our assumptions and estimates or our
assumptions and estimates change due to new information, we may be exposed to an
impairment charge.





During
2006, we reassessed our coal slurry pipeline operation and concluded that the
likelihood of Black Mesa Pipeline 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 Pipeline 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, 2008 and
2007.  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 M of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K for additional
discussion of unconsolidated affiliates.




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Derivatives and Risk Management- 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 account for derivative instruments utilized in





Under
Statement 133, entities are required to record derivative instruments at fair
value, with the exception of normal purchases and normal sales that are expected
to result in physical delivery.  See Note C of the Notes to
Consolidated Financial Statements in this Annual Report on Form 10-K for
additional fair value discussion.  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 changes
occur.  Commodity price volatility may have a significant impact on
the gain 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 reduce
our exposure to fluctuations in natural gas, NGLs and condensate prices, we
periodically enter into futures, forwards, options or swap transactions in order
to hedge anticipated purchases and sales of natural gas, NGLs and condensate and
fuel requirements.  Interest-rate swaps are also used to manage
interest rate risk.  Under certain conditions, we designate these
derivative instruments as a hedge of exposure to changes in fair values or cash
flow.  For hedges of exposure to changes in cash flow, the effective
portion of the gain or loss on the derivative instrument is reported initially
as a component of accumulated other comprehensive income (loss) and subsequently
recorded to earnings when the forecasted transaction affects
earnings.  Any ineffectiveness of designated hedges is reported in
earnings during the period the ineffectiveness occurs.  For hedges of
exposure to changes in fair value, the gain or loss on the derivative instrument
is recognized in earnings during the period of change together with the
offsetting gain or loss on the hedged item attributable to the risk being
hedged.





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





See Note
D of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional 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.  Accruals for
estimated losses from environmental remediation obligations generally are
recognized no later than completion of the remediation feasibility
study.  Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed
probable.  Actual results may differ from our estimates resulting in
an impact, positive or negative, on earnings.  See Note J of the Notes
to Consolidated Financial Statements in this Annual Report on Form 10-K for
additional discussion of contingencies.


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FINANCIAL
RESULTS AND OPERATING INFORMATION





Consolidated
Operations





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




Variances
                                  
                                  VariancesYears
      Ended December 31,
                                  
                                  
                                  2008
      vs. 2007
                                  
                                  2007
      vs. 2006Financial
      Results
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006
                                  
                                  
                                  Increase
      (Decrease)
                                  Increase
      (Decrease)(Millions
      of dollars)Revenues
                                  
                                  $
                                  7,720.2
                                  
                                  
                                  $
                                  5,831.6
                                  
                                  
                                  $
                                  4,738.2
                                  
                                  
                                  $
                                  1,888.6
                                  
                                  
                                  
                                  32
                                  %
                                  
                                  $
                                  1,093.4
                                  
                                  
                                  
                                  23
                                  %Cost
      of sales and fuel
                                  
                                  
                                  6,579.5
                                  
                                  
                                  
                                  4,935.7
                                  
                                  
                                  
                                  3,894.7
                                  
                                  
                                  
                                  1,643.8
                                  
                                  
                                  
                                  33
                                  %
                                  
                                  
                                  1,041.0
                                  
                                  
                                  
                                  27
                                  %Net
      margin
                                  
                                  
                                  1,140.7
                                  
                                  
                                  
                                  895.9
                                  
                                  
                                  
                                  843.5
                                  
                                  
                                  
                                  244.8
                                  
                                  
                                  
                                  27
                                  %
                                  
                                  
                                  52.4
                                  
                                  
                                  
                                  6
                                  %Operating
      costs
                                  
                                  
                                  371.8
                                  
                                  
                                  
                                  337.4
                                  
                                  
                                  
                                  325.8
                                  
                                  
                                  
                                  34.4
                                  
                                  
                                  
                                  10
                                  %
                                  
                                  
                                  11.6
                                  
                                  
                                  
                                  4
                                  %Depreciation
      and amortization
                                  
                                  
                                  124.8
                                  
                                  
                                  
                                  113.7
                                  
                                  
                                  
                                  122.0
                                  
                                  
                                  
                                  11.1
                                  
                                  
                                  
                                  10
                                  %
                                  
                                  
                                  (8.3
                                  )
                                  
                                  
                                  (7
                                  %)Gain
      (loss) on sale of assets
                                  
                                  
                                  0.7
                                  
                                  
                                  
                                  2.0
                                  
                                  
                                  
                                  115.5
                                  
                                  
                                  
                                  (1.3
                                  )
                                  
                                  
                                  (65
                                  %)
                                  
                                  
                                  (113.5
                                  )
                                  
                                  
                                  (98
                                  %)Operating
      income
                                  
                                  $
                                  644.8
                                  
                                  
                                  $
                                  446.8
                                  
                                  
                                  $
                                  511.2
                                  
                                  
                                  $
                                  198.0
                                  
                                  
                                  
                                  44
                                  %
                                  
                                  $
                                  (64.4
                                  )
                                  
                                  
                                  (13
                                  %)Equity
      earnings from investments
                                  
                                  $
                                  101.4
                                  
                                  
                                  $
                                  89.9
                                  
                                  
                                  $
                                  95.9
                                  
                                  
                                  $
                                  11.5
                                  
                                  
                                  
                                  13
                                  %
                                  
                                  $
                                  (6.0
                                  )
                                  
                                  
                                  (6
                                  %)Allowance
      for equity funds used
                                    during
      construction
                                  
                                  $
                                  50.9
                                  
                                  
                                  $
                                  12.5
                                  
                                  
                                  $
                                  2.2
                                  
                                  
                                  $
                                  38.4
                                  
                                  
                                  
                                  *
                                  
                                  
                                  $
                                  10.3
                                  
                                  
                                  
                                  *Other
      income (expense)
                                  
                                  $
                                  (7.7
                                  )
                                  
                                  $
                                  6.7
                                  
                                  
                                  $
                                  (0.6
                                  )
                                  
                                  $
                                  (14.4
                                  )
                                  
                                  
                                  *
                                  
                                  
                                  $
                                  7.3
                                  
                                  
                                  
                                  *Interest
      expense
                                  
                                  $
                                  (151.1
                                  )
                                  
                                  $
                                  (138.9
                                  )
                                  
                                  $
                                  (133.5
                                  )
                                  
                                  $
                                  12.2
                                  
                                  
                                  
                                  9
                                  %
                                  
                                  $
                                  5.4
                                  
                                  
                                  
                                  4
                                  %Minority
      interests in income of
                                    consolidated
      subsidiaries
                                  
                                  $
                                  (0.4
                                  )
                                  
                                  $
                                  (0.4
                                  )
                                  
                                  $
                                  (2.4
                                  )
                                  
                                  $
                                  -
                                  
                                  
                                  
                                  0
                                  %
                                  
                                  $
                                  (2.0
                                  )
                                  
                                  
                                  (83
                                  %)Capital
      expenditures
                                  
                                  $
                                  1,253.9
                                  
                                  
                                  $
                                  709.9
                                  
                                  
                                  $
                                  201.7
                                  
                                  
                                  $
                                  544.0
                                  
                                  
                                  
                                  77
                                  %
                                  
                                  $
                                  508.2
                                  
                                  
                                  
                                  **
      Percentage change is greater than 100 percent.





2008 vs. 2007- Net margin
increased primarily due to the following:


·
            wider
      NGL product price differentials, increased NGL gathering and fractionation
      volumes and certain operational measurement gains, primarily at NGL
      storage caverns, in our Natural Gas Liquids Gathering and Fractionation
      segment;


·
            higher
      realized commodity prices, improved contractual terms and higher volumes
      sold and processed in our Natural Gas Gathering and Processing
      segment;


·
            incremental
      net margin in our Natural Gas Liquids Pipelines segment from the assets
      acquired from Kinder Morgan in October 2007;
and


·
            increased
      transportation and storage margins as a result of the impact of higher
      natural gas prices on retained fuel and new and renegotiated storage
      contracts in our Natural Gas Pipelines
segment.





Operating
costs increased primarily due to incremental operating expenses associated with
the assets acquired from Kinder Morgan, outside services primarily associated
with scheduled maintenance expenses at our Medford and Mont Belvieu
fractionators, and chemical costs.  Operating costs also increased due
to costs associated with the startup of our newly expanded Bushton fractionator
and Overland Pass Pipeline.





Depreciation
and amortization increased primarily due to depreciation expense associated with
our completed capital projects and the assets acquired from Kinder
Morgan.





Equity
earnings from investments increased primarily due to higher gathering revenues
in our various investments as well as a gain on the sale of Bison Pipeline LLC
by Northern Border Pipeline, partially offset by reduced throughput on Northern
Border Pipeline.  We own a 50 percent equity interest in Northern
Border Pipeline.





Allowance
for equity funds used during construction and capital expenditures increased due
to increased spending for our capital projects, which are discussed beginning on
page 38.





Other
income (expense) fluctuated primarily due to investment gains
(losses).





Interest
expense increased primarily due to increased borrowings to fund our capital
projects.




- 43
-
 Table
of Contents


2007 vs. 2006- Net margin
increased primarily due to the following:


·
            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;


·
            higher
      product price differentials and higher isomerization price differentials
      in our Natural Gas Liquids Gathering and Fractionation
      segment;


·
            incremental
      net margin related to the acquired assets from Kinder Morgan in October
      2007 in our Natural Gas Liquids Pipelines segment;
  and


·
            increased
      storage margins in our Natural Gas Pipelines segment; partially offset
      by


·
            decreased
      natural gas transportation margins in our Natural Gas Pipelines segment,
      primarily resulting from lower throughput and higher fuel costs;
      and


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





Operating
costs increased 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 primarily due to a goodwill and asset impairment
charge of $12.0 million recorded in the second quarter of 2006 related to Black
Mesa Pipeline, which is included in our Other segment.





Gain on
sale of assets decreased 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 primarily include earnings from our interest in
Northern Border Pipeline.  The decrease in equity earnings from
investments for 2007 was 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 38 for
discussion of the disposition of the 20 percent partnership interest in Northern
Border Pipeline.





Allowance
for equity funds used during construction and capital expenditures increased due
to our capital projects.





Other
income (expense) fluctuated primarily due to expenses incurred in 2006 related
to costs associated with transitioning operations from Omaha,
Nebraska.





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





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


- 44
-
 Table
of Contents




Natural
Gas Gathering and Processing




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




Variances
                                  
                                  VariancesYears
      Ended December 31,
                                  
                                  
                                  2008
      vs. 2007
                                  
                                  2007
      vs. 2006Financial
      Results
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006
                                  
                                  
                                  Increase
      (Decrease)
                                  
                                  Increase
      (Decrease)(Millions
      of dollars)NGL
      and condensate sales
                                  
                                  $
                                  851.7
                                  
                                  
                                  $
                                  673.8
                                  
                                  
                                  $
                                  646.5
                                  
                                  
                                  $
                                  177.9
                                  
                                  
                                  
                                  26
                                  %
                                  
                                  $
                                  27.3
                                  
                                  
                                  
                                  4
                                  %Residue
      gas sales
                                  
                                  
                                  750.4
                                  
                                  
                                  
                                  636.8
                                  
                                  
                                  
                                  706.3
                                  
                                  
                                  
                                  113.6
                                  
                                  
                                  
                                  18
                                  %
                                  
                                  
                                  (69.5
                                  )
                                  
                                  
                                  (10
                                  %)Gathering,
      compression, dehydration
                                    and
      processing fees and other revenue
                                  
                                  
                                  154.1
                                  
                                  
                                  
                                  148.1
                                  
                                  
                                  
                                  123.2
                                  
                                  
                                  
                                  6.0
                                  
                                  
                                  
                                  4
                                  %
                                  
                                  
                                  24.9
                                  
                                  
                                  
                                  20
                                  %Cost
      of sales and fuel
                                  
                                  
                                  1,321.0
                                  
                                  
                                  
                                  1,092.2
                                  
                                  
                                  
                                  1,105.3
                                  
                                  
                                  
                                  228.8
                                  
                                  
                                  
                                  21
                                  %
                                  
                                  
                                  (13.1
                                  )
                                  
                                  
                                  (1
                                  %)Net
      margin
                                  
                                  
                                  435.2
                                  
                                  
                                  
                                  366.5
                                  
                                  
                                  
                                  370.7
                                  
                                  
                                  
                                  68.7
                                  
                                  
                                  
                                  19
                                  %
                                  
                                  
                                  (4.2
                                  )
                                  
                                  
                                  (1
                                  %)Operating
      costs
                                  
                                  
                                  138.2
                                  
                                  
                                  
                                  135.4
                                  
                                  
                                  
                                  147.5
                                  
                                  
                                  
                                  2.8
                                  
                                  
                                  
                                  2
                                  %
                                  
                                  
                                  (12.1
                                  )
                                  
                                  
                                  (8
                                  %)Depreciation
      and amortization
                                  
                                  
                                  49.9
                                  
                                  
                                  
                                  45.1
                                  
                                  
                                  
                                  43.0
                                  
                                  
                                  
                                  4.8
                                  
                                  
                                  
                                  11
                                  %
                                  
                                  
                                  2.1
                                  
                                  
                                  
                                  5
                                  %Gain
      (loss) on sale of assets
                                  
                                  
                                  -
                                  
                                  
                                  
                                  1.8
                                  
                                  
                                  
                                  0.4
                                  
                                  
                                  
                                  (1.8
                                  )
                                  
                                  
                                  (100
                                  %)
                                  
                                  
                                  1.4
                                  
                                  
                                  
                                  *Operating
      income
                                  
                                  $
                                  247.1
                                  
                                  
                                  $
                                  187.8
                                  
                                  
                                  $
                                  180.6
                                  
                                  
                                  $
                                  59.3
                                  
                                  
                                  
                                  32
                                  %
                                  
                                  $
                                  7.2
                                  
                                  
                                  
                                  4
                                  %Equity
      earnings from investments
                                  
                                  $
                                  32.8
                                  
                                  
                                  $
                                  26.4
                                  
                                  
                                  $
                                  22.6
                                  
                                  
                                  $
                                  6.4
                                  
                                  
                                  
                                  24
                                  %
                                  
                                  $
                                  3.8
                                  
                                  
                                  
                                  17
                                  %Capital
      expenditures
                                  
                                  $
                                  146.2
                                  
                                  
                                  $
                                  83.8
                                  
                                  
                                  $
                                  81.0
                                  
                                  
                                  $
                                  62.4
                                  
                                  
                                  
                                  74
                                  %
                                  
                                  $
                                  2.8
                                  
                                  
                                  
                                  3
                                  %*
      Percentage change is greater than 100 percent.




Years
      Ended December 31,Operating Information(a)
                    
                    2008
                    
                    
                    2007
                    
                    
                    2006Natural
      gas gathered (BBtu/d)
                    
                    
                    1,164
                    
                    
                    
                    1,171
                    
                    
                    
                    1,168Natural
      gas processed(BBtu/d)
                    
                    
                    641
                    
                    
                    
                    621
                    
                    
                    
                    988NGL
      sales (MBbl/d)
                    
                    
                    39
                    
                    
                    
                    38
                    
                    
                    
                    42Residue
      gas sales (BBtu/d)
                    
                    
                    279
                    
                    
                    
                    281
                    
                    
                    
                    302Realized
      composite NGL sales price ($/gallon)
                    
                    $
                    1.27
                    
                    
                    $
                    1.06
                    
                    
                    $
                    0.93Realized
      condensate sales price ($/Bbl)
                    
                    $
                    89.30
                    
                    
                    $
                    67.35
                    
                    
                    $
                    57.84Realized
      residue gas sales price ($/MMBtu)
                    
                    $
                    7.34
                    
                    
                    $
                    6.21
                    
                    
                    $
                    6.31Realized
      gross processing spread ($/MMBtu)
                    
                    $
                    7.47
                    
                    
                    $
                    5.21
                    
                    
                    $
                    5.05(a)
      - Includes volumes for consolidated entities only.




Years
      Ended December 31,Operating Information(a)
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006Percent
      of proceedsWellhead
      purchases (MMBtu/d)
                  
                  
                  67,718
                  
                  
                  
                  83,993
                  
                  
                  
                  121,199NGL
      sales (Bbl/d)
                  
                  
                  6,223
                  
                  
                  
                  5,959
                  
                  
                  
                  7,364Residue
      gas sales (MMBtu/d)
                  
                  
                  39,724
                  
                  
                  
                  34,010
                  
                  
                  
                  28,855Condensate
      sales(Bbl/d)
                  
                  
                  928
                  
                  
                  
                  719
                  
                  
                  
                  1,103Percentage
      of total net margin
                  
                  
                  62%
                  
                  
                  
                  56%
                  
                  
                  
                  55%Fee-basedWellhead
      volumes (MMBtu/d)
                  
                  
                  1,164,273
                  
                  
                  
                  1,170,502
                  
                  
                  
                  1,168,478Average
      rate ($/MMBtu)
                  
                  $
                  0.26
                  
                  
                  $
                  0.25
                  
                  
                  $
                  0.25Percentage
      of total net margin
                  
                  
                  23%
                  
                  
                  
                  30%
                  
                  
                  
                  29%Keep-wholeNGL
      shrink (MMBtu/d)
                  
                  
                  21,354
                  
                  
                  
                  23,636
                  
                  
                  
                  37,029Plant
      fuel (MMBtu/d)
                  
                  
                  2,288
                  
                  
                  
                  2,846
                  
                  
                  
                  4,959Condensate
      shrink (MMBtu/d)
                  
                  
                  1,825
                  
                  
                  
                  2,490
                  
                  
                  
                  3,328Condensate
      sales (Bbl/d)
                  
                  
                  369
                  
                  
                  
                  504
                  
                  
                  
                  683Percentage
      of total net margin
                  
                  
                  15%
                  
                  
                  
                  14%
                  
                  
                  
                  16%(a)
      - Includes volumes for consolidated entities only.




- 45
-
 Table
of Contents


2008 vs. 2007 - Net margin
increased primarily due to the following:


·
            an
      increase of $58.4 million due to higher realized commodity
      prices;


·
            an
      increase of $11.9 million due to improved contractual
    terms;


·
            an
      increase of $7.0 million due to higher volumes sold and processed;
      partially offset by


·
            a
      decrease of $8.6 million due to a one-time favorable contract settlement
      that occurred in the fourth quarter of
2007.





During
September 2008, the disruption in the Gulf Coast area related to Hurricane Ike
limited our ability to process and deliver natural gas and NGL volumes from our
Mid-Continent processing plants.  Without this volume reduction, we
estimate net margin would have been approximately $1.8 million
higher.  During the fourth quarter of 2008, we experienced operational
interruptions at our Grasslands plant that we estimate reduced our net margin by
approximately $2.7 million and weather-related interruptions are estimated to
have reduced our net margin by approximately $2.1 million.





Operating
costs increased primarily due to increased costs for chemicals and maintenance
parts, and a favorable legal settlement received in June 2007, which reduced
legal costs for 2007.  These increases were partially offset by
decreased equipment lease costs in 2008 associated with the Bushton
Plant.





Depreciation
and amortization increased primarily as a result of depreciation expense
associated with our completed capital projects.





Equity
earnings from investments increased primarily due to higher gathering revenues
in our Fort Union Gas Gathering investment as a result of capacity
expansions.





Capital
expenditures increased due to our increased growth activities, primarily in the
Rocky Mountain region.





2007 vs. 2006 - Net margin
decreased 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 a one-time favorable contract settlement
      that occurred in the fourth quarter of 2007;
and


·
            an
      increase of $5.5 million due to higher realized NGL and natural gas
      prices.





Operating
costs decreased 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 primarily due to our capital
projects.





Equity
earnings from investments increased primarily due to 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.





Commodity Price Risk - Our
Natural Gas Gathering and Processing segment is exposed to commodity price risk,
primarily from NGLs, as a result of receiving commodities in exchange for our
services.  A small percentage of our services, based on volume, is
provided through keep-whole arrangements.  See discussion regarding
our commodity price risk beginning on page 60 under “Commodity Price Risk” in
Item 7A, Quantitative and Qualitative Disclosures about Market
Risk.


- 46
-
 Table
of Contents


Natural
Gas Pipelines





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




Variances
                                    
                                    VariancesYears
      Ended December 31,
                                    
                                    
                                    2008
      vs. 2007
                                    
                                    2007
      vs. 2006Financial
      Results
                                    
                                    2008
                                    
                                    
                                    2007
                                    
                                    
                                    2006
                                    
                                    
                                    Increase
      (Decrease)
                                    
                                    Increase
      (Decrease)(Millions
      of dollars)Transportation
      revenues
                                    
                                    $
                                    240.0
                                    
                                    
                                    $
                                    225.4
                                    
                                    
                                    $
                                    232.1
                                    
                                    
                                    $
                                    14.6
                                    
                                    
                                    
                                    6
                                    %
                                    
                                    $
                                    (6.7
                                    )
                                    
                                    
                                    (3
                                    %)Storage
      revenues
                                    
                                    
                                    63.7
                                    
                                    
                                    
                                    54.8
                                    
                                    
                                    
                                    49.5
                                    
                                    
                                    
                                    8.9
                                    
                                    
                                    
                                    16
                                    %
                                    
                                    
                                    5.3
                                    
                                    
                                    
                                    11
                                    %Gas
      sales and other revenues
                                    
                                    
                                    38.4
                                    
                                    
                                    
                                    21.8
                                    
                                    
                                    
                                    35.4
                                    
                                    
                                    
                                    16.6
                                    
                                    
                                    
                                    76
                                    %
                                    
                                    
                                    (13.6
                                    )
                                    
                                    
                                    (38
                                    %)Cost
      of sales
                                    
                                    
                                    84.7
                                    
                                    
                                    
                                    60.9
                                    
                                    
                                    
                                    70.2
                                    
                                    
                                    
                                    23.8
                                    
                                    
                                    
                                    39
                                    %
                                    
                                    
                                    (9.3
                                    )
                                    
                                    
                                    (13
                                    %)Net
      margin
                                    
                                    
                                    257.4
                                    
                                    
                                    
                                    241.1
                                    
                                    
                                    
                                    246.8
                                    
                                    
                                    
                                    16.3
                                    
                                    
                                    
                                    7
                                    %
                                    
                                    
                                    (5.7
                                    )
                                    
                                    
                                    (2
                                    %)Operating
      costs
                                    
                                    
                                    89.9
                                    
                                    
                                    
                                    96.6
                                    
                                    
                                    
                                    91.5
                                    
                                    
                                    
                                    (6.7
                                    )
                                    
                                    
                                    (7
                                    %)
                                    
                                    
                                    5.1
                                    
                                    
                                    
                                    6
                                    %Depreciation
      and amortization
                                    
                                    
                                    34.3
                                    
                                    
                                    
                                    32.4
                                    
                                    
                                    
                                    32.8
                                    
                                    
                                    
                                    1.9
                                    
                                    
                                    
                                    6
                                    %
                                    
                                    
                                    (0.4
                                    )
                                    
                                    
                                    (1
                                    %)Gain
      (loss) on sale of assets
                                    
                                    
                                    -
                                    
                                    
                                    
                                    0.1
                                    
                                    
                                    
                                    114.9
                                    
                                    
                                    
                                    (0.1
                                    )
                                    
                                    
                                    (100
                                    %)
                                    
                                    
                                    (114.8
                                    )
                                    
                                    
                                    (100
                                    %)Operating
      income
                                    
                                    $
                                    133.2
                                    
                                    
                                    $
                                    112.2
                                    
                                    
                                    $
                                    237.4
                                    
                                    
                                    $
                                    21.0
                                    
                                    
                                    
                                    19
                                    %
                                    
                                    $
                                    (125.2
                                    )
                                    
                                    
                                    (53
                                    %)Equity
      earnings from investments
                                    
                                    $
                                    66.7
                                    
                                    
                                    $
                                    62.5
                                    
                                    
                                    $
                                    72.8
                                    
                                    
                                    $
                                    4.2
                                    
                                    
                                    
                                    7
                                    %
                                    
                                    $
                                    (10.3
                                    )
                                    
                                    
                                    (14
                                    %)Allowance
      for equity funds used
                                      during
      construction
                                    
                                    $
                                    14.0
                                    
                                    
                                    $
                                    3.6
                                    
                                    
                                    $
                                    0.9
                                    
                                    
                                    $
                                    10.4
                                    
                                    
                                    
                                    *
                                    
                                    
                                    $
                                    2.7
                                    
                                    
                                    
                                    *Capital
      expenditures
                                    
                                    $
                                    267.0
                                    
                                    
                                    $
                                    138.9
                                    
                                    
                                    $
                                    48.6
                                    
                                    
                                    $
                                    128.1
                                    
                                    
                                    
                                    92
                                    %
                                    
                                    $
                                    90.3
                                    
                                    
                                    
                                    **
      Percentage change is greater than 100 percent.




Years
      Ended December 31,Operating Information
      (a)
                          
                          2008
                          
                          
                          2007
                          
                          
                          2006Natural
      gas transported (MMcf/d)
                          
                          
                          3,665
                          
                          
                          
                          3,579
                          
                          
                          
                          3,634Average
      natural gas priceMid-Continent
      region  ($/MMBtu)
                          
                          $
                          7.17
                          
                          
                          $
                          6.05
                          
                          
                          $
                          6.04(a)
      - Includes volumes for consolidated entities only.




2008 vs. 2007- Net margin
increased due to the following:


·
            an
      increase of $6.3 million due to higher natural gas transportation margins,
      primarily as a result of the impact of higher natural gas prices on
      retained fuel;


·
            an
      increase of $5.4 million due to higher natural gas storage margins,
      primarily related to new and renegotiated natural gas storage contracts
      and the impact of higher natural gas prices on retained fuel;
      and


·
            an
      increase of $3.8 million due to increased operational natural gas
      inventory sales.





Operating
costs decreased primarily due to lower general taxes and lower general operating
costs, which includes decreased employee-related costs.





Depreciation
and amortization increased primarily as a result of depreciation expense
associated with our completed capital projects.





Equity
earnings from investments increased primarily due to an $8.3 million gain on the
sale of Bison Pipeline LLC by Northern Border Pipeline, partially offset by
reduced throughput on Northern Border Pipeline.  We own a 50 percent
equity interest in Northern Border Pipeline.





Allowance
for equity funds used during construction and capital expenditures increased
primarily due to increased spending for our capital projects, which are
discussed beginning on page 38.





2007 vs. 2006 - Net margin
decreased 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


- 47
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 Table
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·
            an
      increase of $5.4 million from natural gas storage margins as a result of
      new and renegotiated contracts.





Operating
costs increased primarily due to higher employee-related costs.





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.





Equity
earnings from investments primarily include earnings from our interest in
Northern Border Pipeline.  The decrease in equity earnings from
investments 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 38 for discussion
of the disposition of the 20 percent partnership interest in Northern Border
Pipeline.





Allowance
for equity funds used during construction and capital expenditures increased
primarily due to our capital projects.




Natural
Gas Liquids Gathering and Fractionation




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




Variances
                                  
                                  VariancesYears
      Ended December 31,
                                  
                                  
                                  2008
      vs. 2007
                                  
                                  2007
      vs. 2006Financial
      Results
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006
                                  
                                  
                                  Increase
      (Decrease)
                                  
                                  Increase
      (Decrease)(Millions
      of dollars)NGL
      and condensate sales
                                  
                                  $
                                  5,944.0
                                  
                                  
                                  $
                                  4,314.8
                                  
                                  
                                  $
                                  3,299.3
                                  
                                  
                                  $
                                  1,629.2
                                  
                                  
                                  
                                  38
                                  %
                                  
                                  $
                                  1,015.5
                                  
                                  
                                  
                                  31
                                  %Storage
      and fractionation revenues
                                  
                                  
                                  325.7
                                  
                                  
                                  
                                  272.5
                                  
                                  
                                  
                                  193.7
                                  
                                  
                                  
                                  53.2
                                  
                                  
                                  
                                  20
                                  %
                                  
                                  
                                  78.8
                                  
                                  
                                  
                                  41
                                  %Cost
      of sales and fuel
                                  
                                  
                                  5,952.0
                                  
                                  
                                  
                                  4,381.5
                                  
                                  
                                  
                                  3,326.0
                                  
                                  
                                  
                                  1,570.5
                                  
                                  
                                  
                                  36
                                  %
                                  
                                  
                                  1,055.5
                                  
                                  
                                  
                                  32
                                  %Net
      margin
                                  
                                  
                                  317.7
                                  
                                  
                                  
                                  205.8
                                  
                                  
                                  
                                  167.0
                                  
                                  
                                  
                                  111.9
                                  
                                  
                                  
                                  54
                                  %
                                  
                                  
                                  38.8
                                  
                                  
                                  
                                  23
                                  %Operating
      costs
                                  
                                  
                                  89.8
                                  
                                  
                                  
                                  70.7
                                  
                                  
                                  
                                  57.5
                                  
                                  
                                  
                                  19.1
                                  
                                  
                                  
                                  27
                                  %
                                  
                                  
                                  13.2
                                  
                                  
                                  
                                  23
                                  %Depreciation
      and amortization
                                  
                                  
                                  23.5
                                  
                                  
                                  
                                  23.1
                                  
                                  
                                  
                                  20.7
                                  
                                  
                                  
                                  0.4
                                  
                                  
                                  
                                  2
                                  %
                                  
                                  
                                  2.4
                                  
                                  
                                  
                                  12
                                  %Operating
      income
                                  
                                  $
                                  204.4
                                  
                                  
                                  $
                                  112.0
                                  
                                  
                                  $
                                  88.8
                                  
                                  
                                  $
                                  92.4
                                  
                                  
                                  
                                  83
                                  %
                                  
                                  $
                                  23.2
                                  
                                  
                                  
                                  26
                                  %Capital
      expenditures
                                  
                                  $
                                  169.5
                                  
                                  
                                  $
                                  123.6
                                  
                                  
                                  $
                                  21.8
                                  
                                  
                                  $
                                  45.9
                                  
                                  
                                  
                                  37
                                  %
                                  
                                  $
                                  101.8
                                  
                                  
                                  
                                  **
      Percentage change is greater than 100 percent.




Years
      Ended December 31,Operating
      Information
                        
                        2008
                        
                        
                        2007
                        
                        
                        2006NGLs
      gathered (MBbl/d)
                        
                        
                        271
                        
                        
                        
                        248
                        
                        
                        
                        226NGL
      sales (MBbl/d)
                        
                        
                        283
                        
                        
                        
                        231
                        
                        
                        
                        207NGLs
      fractionated (MBbl/d)
                        
                        
                        373
                        
                        
                        
                        356
                        
                        
                        
                        313Conway-to-Mont
      Belvieu OPIS average price differentialEthane
      ($/gallon)
                        
                        $
                        0.15
                        
                        
                        $
                        0.06
                        
                        
                        $
                        0.05




2008 vs. 2007- Net margin
increased due to the following:


·
            an
      increase of $70.8 million due to wider product price differentials between
      Conway, Kansas, and Mont Belvieu,
Texas;


·
            an
      increase of $32.1 million due to higher exchange margins, primarily driven
      by increased gathering and fractionation
  volumes;


·
            an
      increase of $8.4 million from certain operational measurement gains,
      primarily at NGL storage caverns;
and


·
            an
      increase of $3.6 million due to higher storage margins in our
      Mid-Continent storage business.





During
September 2008, Hurricane Ike caused disruptions to our gathering and
fractionation operations in the Mid-Continent and Gulf Coast
regions.  Without this disruption, we estimate net margin would have
been approximately $3.8 million higher.





Operating
costs increased primarily due to costs associated with the startup of our newly
expanded Bushton fractionator, maintenance projects at our Medford fractionator,
increased lease costs for our Bushton facility and expenses related to a planned
maintenance shutdown at our Mont Belvieu fractionator.


- 48
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Capital
expenditures increased primarily due to our growth activities and the associated
expansion of the Bushton facility.  See discussion of our capital
projects beginning on page 38.





2007 vs. 2006 - Net margin
increased 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 differentials and
      higher isomerization price differentials;
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 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.





Capital
expenditures increased primarily due to our growth activities and the associated
expansion of the Bushton facility.





Natural
Gas Liquids Pipelines





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




Variances
                                  
                                  VariancesYears
      Ended December 31,
                                  
                                  
                                  2008
      vs. 2007
                                  
                                  2007
      vs. 2006Financial
      Results
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006
                                  
                                  
                                  Increase
      (Decrease)
                                  
                                  Increase
      (Decrease)(Millions
      of dollars)Transportation
      and gathering revenues
                                  
                                  $
                                  148.9
                                  
                                  
                                  $
                                  90.4
                                  
                                  
                                  $
                                  66.4
                                  
                                  
                                  $
                                  58.5
                                  
                                  
                                  
                                  65
                                  %
                                  
                                  $
                                  24.0
                                  
                                  
                                  
                                  36
                                  %Storage
      revenues
                                  
                                  
                                  4.8
                                  
                                  
                                  
                                  0.8
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  4.0
                                  
                                  
                                  
                                  *
                                  
                                  
                                  
                                  0.8
                                  
                                  
                                  
                                  100
                                  %NGL
      sales and other revenues
                                  
                                  
                                  3.4
                                  
                                  
                                  
                                  0.6
                                  
                                  
                                  
                                  0.1
                                  
                                  
                                  
                                  2.8
                                  
                                  
                                  
                                  *
                                  
                                  
                                  
                                  0.5
                                  
                                  
                                  
                                  *Cost
      of sales and fuel
                                  
                                  
                                  24.3
                                  
                                  
                                  
                                  10.2
                                  
                                  
                                  
                                  6.1
                                  
                                  
                                  
                                  14.1
                                  
                                  
                                  
                                  *
                                  
                                  
                                  
                                  4.1
                                  
                                  
                                  
                                  67
                                  %Net
      margin
                                  
                                  
                                  132.8
                                  
                                  
                                  
                                  81.6
                                  
                                  
                                  
                                  60.4
                                  
                                  
                                  
                                  51.2
                                  
                                  
                                  
                                  63
                                  %
                                  
                                  
                                  21.2
                                  
                                  
                                  
                                  35
                                  %Operating
      costs
                                  
                                  
                                  55.1
                                  
                                  
                                  
                                  29.0
                                  
                                  
                                  
                                  19.3
                                  
                                  
                                  
                                  26.1
                                  
                                  
                                  
                                  90
                                  %
                                  
                                  
                                  9.7
                                  
                                  
                                  
                                  50
                                  %Depreciation
      and amortization
                                  
                                  
                                  17.1
                                  
                                  
                                  
                                  13.1
                                  
                                  
                                  
                                  12.0
                                  
                                  
                                  
                                  4.0
                                  
                                  
                                  
                                  31
                                  %
                                  
                                  
                                  1.1
                                  
                                  
                                  
                                  9
                                  %Operating
      income
                                  
                                  $
                                  60.6
                                  
                                  
                                  $
                                  39.5
                                  
                                  
                                  $
                                  29.1
                                  
                                  
                                  $
                                  21.1
                                  
                                  
                                  
                                  53
                                  %
                                  
                                  $
                                  10.4
                                  
                                  
                                  
                                  36
                                  %Equity
      earnings from investments
                                  
                                  $
                                  2.0
                                  
                                  
                                  $
                                  1.0
                                  
                                  
                                  $
                                  0.4
                                  
                                  
                                  $
                                  1.0
                                  
                                  
                                  
                                  100
                                  %
                                  
                                  $
                                  0.6
                                  
                                  
                                  
                                  *Allowance
      for equity funds used
                                    during
      construction
                                  
                                  $
                                  36.9
                                  
                                  
                                  $
                                  8.9
                                  
                                  
                                  $
                                  1.3
                                  
                                  
                                  $
                                  28.0
                                  
                                  
                                  
                                  *
                                  
                                  
                                  $
                                  7.6
                                  
                                  
                                  
                                  *Capital
      expenditures
                                  
                                  $
                                  670.9
                                  
                                  
                                  $
                                  363.5
                                  
                                  
                                  $
                                  49.3
                                  
                                  
                                  $
                                  307.4
                                  
                                  
                                  
                                  85
                                  %
                                  
                                  $
                                  314.2
                                  
                                  
                                  
                                  **
      Percentage change is greater than 100 percent.




Years
      Ended December 31,Operating
      Information
                      
                      2008
                      
                      
                      2007
                      
                      
                      2006NGLs
      transported (MBbl/d)
                      
                      
                      333
                      
                      
                      
                      299
                      
                      
                      
                      200NGLs
      gathered (MBbl/d)
                      
                      
                      76
                      
                      
                      
                      61
                      
                      
                      
                      40




2008 vs. 2007- Net margin
increased primarily as a result of:


·
            an
      increase of $44.3 million in incremental margin from the assets acquired
      from Kinder Morgan in October 2007, including $10.3 million due to
      increased throughput during the fourth quarter of 2008, compared with the
      fourth quarter of 2007;


·
            an
      increase of $4.3 million due to increased throughput from new supply
      connections, increased production volumes from existing supply connections
      to our natural gas liquids gathering pipelines, and increased throughput
      on our natural gas liquids distribution pipelines;
  and


·
            an
      increase of $2.6 million in incremental margin from Overland Pass
      Pipeline, which began operating during the fourth quarter of
      2008.


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During
September 2008, the disruption in the Gulf Coast area related to Hurricane Ike
reduced transportation and gathering volumes on our pipeline assets between the
Mid-Continent fractionation facilities and the natural gas liquids market hubs
in Conway, Kansas, and Mont Belvieu, Texas.  Without this volume
reduction, we estimate net margin would have been approximately $2.2 million
higher.





Operating
costs increased primarily due to $20.6 million in incremental operating expenses
associated with the assets acquired from Kinder Morgan, as well as higher
employee-related costs and outside services, and costs associated with the
startup of Overland Pass Pipeline operations.





Depreciation
and amortization increased primarily due to the assets acquired from Kinder
Morgan and the startup of Overland Pass Pipeline operations.





Allowance
for equity funds used during construction and capital expenditures increased
primarily due to our growth activities.  See discussion of our capital
projects beginning on page 38.





2007 vs. 2006 - Net margin
increased due to the following:


·
            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.





Operating
costs increased 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 primarily due to incremental operating expenses
associated with our acquired assets from Kinder Morgan.





Allowance
for equity funds used during construction and capital expenditures increased
primarily due to our growth activities.




Other




In the
second quarter of 2008, we started the decommissioning of Black Mesa
Pipeline.  We do not expect the decommissioning to have a material
impact on our consolidated financial statements.





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.





FERC Matter-As a result of a transaction
that was brought to the attention of one of our affiliates by a third party, we
conducted an internal review of transactions that may have violated FERC natural
gas capacity release rules or related rules and determined that there were
transactions that should be disclosed to the FERC.  We notified the
FERC of this review and filed a report with the FERC regarding these
transactions in March 2008.  We cooperated fully with the FERC in its
investigation of this matter and have taken steps to better ensure that current
and future transactions comply with applicable FERC regulations by implementing
a compliance plan dealing with capacity release.  We, along with
ONEOK, entered into a global settlement with the FERC to resolve this matter and
other FERC enforcement matters, which was approved by the FERC on January 15,
2009.  The global settlement provides for a total civil penalty of
$4.5 million and approximately $2.2 million in disgorgement of profits and
interest.  We are responsible for $1.7 million in civil penalties,
which is recorded as a liability on our Consolidated Balance Sheet as of
December 31, 2008, and the disgorgement of profits and interests are the
responsibility of ONEOK.  We made the required payments in January
2009.




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 common units.  We fund our
operating expenses, debt service and cash distributions to our limited partners
and general partner primarily with operating cash flow.  We have no
material guarantees or other similar commitments to unaffiliated
parties.


- 50
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 Table
of Contents


During
2008 and continuing into 2009, the capital markets experienced volatility and
disruption, which could limit our access to those markets or increase the cost
of issuing new securities in the future.  During this period, we have
continued to have access to our Partnership Credit Agreement to fund our
short-term liquidity needs.  In 2008, we issued common units and
received additional contributions from our general partner.  See
discussion below under “Equity Issuance” for more information.  In
2007, we issued $600 million of long-term notes.  See discussion below
under “Debt Issuance” for more information.





We expect
continued deteriorating economic conditions in 2009, with downward pressures,
relative to 2008, on commodity prices.  We also expect continued
volatility and disruption in the financial markets, which could result in
increased cost of capital.  Our ability to continue to access capital
markets for debt and equity financing under reasonable terms depends on our
financial condition, credit ratings and market conditions.  We
anticipate that our cash flow generated from operations, existing capital
resources, and ability to obtain financing will enable us to maintain our
current level of operations and our planned operations, collateral requirements
and capital expenditures.





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




Years
      Ended December 31,2008
                    
                    
                    2007Long-term
      debt
                    
                    
                    47%
                    
                    
                    
                    54%Equity
                    
                    
                    53%
                    
                    
                    
                    46%Debt
      (including notes payable)
                    
                    
                    54%
                    
                    
                    
                    55%Equity
                    
                    
                    46%
                    
                    
                    
                    45%





Cash Management- We use a
centralized cash management program that concentrates the cash assets of our
operating subsidiaries in joint accounts for the purpose of providing financial
flexibility and lowering the cost of borrowing, transaction costs and bank
fees.  Our centralized cash management program provides that funds in
excess of the daily needs of our operating subsidiaries are concentrated,
consolidated or made available for use by other entities within our consolidated
group.  Our operating subsidiaries participate in this program to the
extent they are permitted under FERC regulations.  Under the cash
management program, depending on whether a participating subsidiary has
short-term cash surpluses or cash requirements, the Intermediate Partnership
provides cash to the subsidiary or the subsidiary provides cash to the
Intermediate Partnership.





Short-term Liquidity - Our
principal sources of short-term liquidity consist of cash generated from
operating activities and our $1.0 billion Partnership Credit
Agreement.  We provide for additional liquidity by maintaining an
amount of excess borrowing capacity related to our Partnership Credit Agreement,
which can be used for general partnership purposes.





During
late 2008, we decided to borrow under our Partnership Credit Agreement to fund
our anticipated working capital requirements for the remainder of 2008 and into
2009.





The total
amount of short-term borrowings authorized by our general partner’s Board of
Directors is $1.5 billion.  At December 31, 2008, we had $870 million
of borrowings outstanding and $130 million available under our Partnership
Credit Agreement and available cash and cash equivalents of approximately $177.6
million.  As of December 31, 2008, we could have issued $772.6 million
of additional short- and long-term debt under the most restrictive provisions
contained in our Partnership Credit Agreement.





We have
an outstanding $25 million letter of credit issued by Royal Bank of Canada,
which is used for counterparty credit support.





We also
have a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement
Agreement with Wells Fargo Bank, N.A., of which $12 million is currently being
used, and an agreement with Royal Bank of Canada, pursuant to which a $12
million letter of credit was issued.  Both agreements are used to
support various permits required by the KDHE for our ongoing business in
Kansas.





Under our
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 plus minority interest in income of consolidated subsidiaries,
distributions received from investments and EBITDA related to any approved
capital projects less equity earnings from investments and the equity
portion of AFUDC) of no more than 5 to 1.  If we consummate one or
more acquisitions in which the aggregate purchase price is $25 million
or


- 51
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 Table
of Contents


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 in our Partnership Credit Agreement, amounts outstanding
under such agreement may become immediately due and payable.  At
December 31, 2008, our ratio of indebtedness to adjusted EBITDA was 4.1 to 1,
and we were in compliance with all covenants under our Partnership Credit
Agreement.





The
average interest rate on our short-term debt outstanding at December 31, 2008,
was 4.22 percent, compared with a weighted average of 3.94 percent for the year
ended December 31, 2008.  Based on the forward LIBOR curve, we expect
the interest rate on our short-term borrowing to decrease in 2009, compared with
2008.





Long-term Financing - In
addition to our principal sources of short-term liquidity discussed above,
options available to us to meet our longer-term cash requirements include the
issuance of common units or long-term notes.  Other options to obtain
financing include, but are not limited to, issuance of convertible debt
securities and asset securitization and sale/leaseback of
facilities.





We are
subject, however, to changes in the equity and debt markets, and there can be no
assurance we will be able or willing to access the public or private markets for
the issuance of common units or long-term debt.  We may choose to meet
our cash requirements by utilizing some combination of cash flows from
operations, borrowings under existing credit facilities, altering the timing of
controllable expenditures, restricting future acquisitions and capital projects,
or pursuing other debt or equity financing alternatives, which may include
issuing common units to ONEOK in a private placement
transaction.  Some of these alternatives could involve higher costs or
negatively affect our credit ratings, among other factors.  Based on
our investment-grade credit ratings, general financial condition and market
expectations regarding our future earnings and projected cash flows, we believe
that we will be able to meet our cash requirements and maintain our
investment-grade credit ratings.





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.





Debt Covenants - The
indenture governing the 2037 Notes 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.




Our $250
million and $225 million senior notes, 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.





Equity Issuance- In March 2008, we
completed a public offering of 2.5 million common units at $58.10 per common
unit, generating net proceeds of approximately $140.4 million after deducting
underwriting discounts but before offering expenses.  In addition, we
sold 5.4 million common units to ONEOK in a private placement, generating
proceeds of approximately $303.2 million.  In conjunction with the
public offering of common units and the private placement, ONEOK Partners GP
contributed $9.4 million in order to maintain its 2 percent general partner
interest in us.





In April
2008, we sold an additional 128,873 common units at $58.10 per common unit to
the underwriters of the public offering upon the partial exercise of their
option to purchase additional common units to cover
over-allotments.  We received


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net
proceeds of approximately $7.2 million from the sale of the common units after
deducting underwriting discounts but before offering expenses.  In
conjunction with the partial exercise by the underwriters, ONEOK Partners GP
contributed $0.2 million in order to maintain its 2 percent general partner
interest in us.  As a result of these transactions, ONEOK now holds a
47.7 percent aggregate equity interest in us.





We used a
portion of the proceeds from the sale of common units and the general partner
contributions to repay borrowings under our Partnership Credit
Agreement.





Capital Expenditures-
Our capital expenditures are typically financed through operating cash flows,
short- and long-term debt and the issuance of equity.  For 2008, our
capital expenditures were also financed through the issuance of common
units.  Capital expenditures were $1,253.9 million and $709.9 million
for 2008 and 2007, respectively, exclusive of acquisitions.  The
increase in capital expenditures for 2008, compared with 2007, is driven
primarily by our internal capital projects, which are discussed beginning on
page 38.  We expect to continue to finance future capital expenditures
with a combination of operating cash flows, short- and long-term debt, and the
issuance of common units.





We
classify expenditures that are expected to generate additional revenue or
significant operating efficiencies as growth capital
expenditures.  Maintenance capital expenditures are those required to
maintain existing operations and do not generate additional
revenues.





The
following tables set forth our growth and maintenance capital expenditures for
2008, 2007 and 2006.




Growth
      Capital Expenditures
                        
                        2008
                        
                        
                        2007
                        
                        
                        2006(Millions
      of dollars)Natural
      Gas Gathering and Processing
                        
                        $
                        123.0
                        
                        
                        $
                        64.8
                        
                        
                        $
                        59.4Natural
      Gas Pipelines
                        
                        
                        241.0
                        
                        
                        
                        123.6
                        
                        
                        
                        28.5Natural
      Gas Liquids Gathering and Fractionation
                        
                        
                        143.8
                        
                        
                        
                        102.4
                        
                        
                        
                        7.0Natural
      Gas Liquids Pipelines
                        
                        
                        664.2
                        
                        
                        
                        359.5
                        
                        
                        
                        39.8Total
      growth capital expenditures
                        
                        $
                        1,172.0
                        
                        
                        $
                        650.3
                        
                        
                        $
                        134.7






Maintenance
      Capital Expenditures
                      
                      2008
                      
                      
                      2007
                      
                      
                      2006(Millions
      of dollars)Natural
      Gas Gathering and Processing
                      
                      $
                      23.2
                      
                      
                      $
                      19.0
                      
                      
                      $
                      21.6Natural
      Gas Pipelines
                      
                      
                      26.0
                      
                      
                      
                      15.3
                      
                      
                      
                      20.1Natural
      Gas Liquids Gathering and Fractionation
                      
                      
                      25.7
                      
                      
                      
                      21.2
                      
                      
                      
                      14.7Natural
      Gas Liquids Pipelines
                      
                      
                      6.7
                      
                      
                      
                      4.0
                      
                      
                      
                      9.5Other
                      
                      
                      0.3
                      
                      
                      
                      0.1
                      
                      
                      
                      1.1Total
      maintenance capital expenditures
                      
                      $
                      81.9
                      
                      
                      $
                      59.6
                      
                      
                      $
                      67.0





The
following table summarizes our 2009 projected growth and maintenance capital
expenditures, excluding AFUDC.




2009
      Projected Capital Expenditures
                      
                      Growth
                      
                      
                      Maintenance
                      
                      
                      Total(Millions
      of dollars)Natural
      Gas Gathering and Processing
                      
                      $
                      98
                      
                      
                      $
                      21
                      
                      
                      $
                      119Natural
      Gas Pipelines
                      
                      
                      38
                      
                      
                      
                      24
                      
                      
                      
                      62Natural
      Gas Liquids Gathering and Fractionation
                      
                      
                      56
                      
                      
                      
                      15
                      
                      
                      
                      71Natural
      Gas Liquids Pipelines
                      
                      
                      163
                      
                      
                      
                      10
                      
                      
                      
                      173Total
      projected capital expenditures
                      
                      $
                      355
                      
                      
                      $
                      70
                      
                      
                      $
                      425





Projected
2009 capital expenditures are significantly less than 2008 capital expenditures
due to the completion of the Overland Pass Pipeline and related projects and the
Guardian Pipeline expansion and extension.  Additional information
about our growth capital expenditures is included under “Capital Projects” on
page 38.  We anticipate spending a total of $300 million to $500
million per year on growth capital expenditures for the years 2010 through
2015.





Investment in Northern Border
Pipeline - Northern Border Pipeline anticipates an equity contribution of
approximately $85 million that will be required of its partners in 2009, of
which our share will be approximately $43 million for our 50 percent equity
interest.




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Credit Ratings - Our credit
ratings as of December 31, 2008, are shown in the table below.




Rating
      Agency
                        Rating
                        OutlookMoody’s
                        Baa2
                        StableS&P
                        BBB
                        Stable




Our
credit ratings, which are currently investment grade, 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.  We do not anticipate a downgrade in our credit
ratings.  However, if our credit ratings were downgraded, the interest
rates on borrowings under our Partnership Credit Agreement would increase,
resulting in an increase in our cost to borrow funds.  An adverse
rating change alone is not a default under our Partnership Credit
Agreement.  See additional discussion about our credit ratings under
“Debt Covenants.”




In the
event of a default under our senior notes, 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.





Other
than the note repurchase obligations described under “Debt Covenants,” 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.





In the
normal course of business, our counterparties provide us with secured and
unsecured credit.  In the event of a downgrade in our credit rating or
a significant change in our counterparties’ evaluation of our creditworthiness,
we could be asked to provide additional collateral in the form of cash, letters
of credit or other negotiable instruments.





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 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 cash distributions paid, including our general
partner’s incentive distribution interests, during the periods
indicated.




Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006(Millions
      of dollars)Common
      unitholders
                    
                    $
                    220.6
                    
                    
                    $
                    184.7
                    
                    
                    $
                    167.0Class
      B unitholders
                    
                    
                    153.5
                    
                    
                    
                    145.2
                    
                    
                    
                    70.1General
      Partner
                    
                    
                    78.9
                    
                    
                    
                    54.7
                    
                    
                    
                    28.4Total
      cash distributions paid
                    
                    $
                    453.0
                    
                    
                    $
                    384.6
                    
                    
                    $
                    265.5





The
following summarizes our quarterly cash distribution activity for
2008:


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


·
            In
      April 2008, we increased our cash distribution to $1.04 per unit for the
      first quarter of 2008.  The distribution was paid on May 15,
      2008, to unitholders of record as of April 30,
  2008;


·
            In
      July 2008, we increased our cash distribution to $1.06 per unit for the
      second quarter of 2008.  The distribution was paid on August 14,
      2008, to unitholders of record as of July 31, 2008;
  and


·
            In
      October 2008, we increased our cash distribution to $1.08 per unit for the
      third quarter of 2008.  The distribution was paid on November
      14, 2008, to unitholders of record as of October 31,
  2008.





In
January 2009, we declared a cash distribution of $1.08 per unit ($4.32 per unit
on an annualized basis) for the fourth quarter of 2008.  The
distribution was paid on February 13, 2009, to unitholders of record as of
January 30, 2009.


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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.





Commodity Prices - We are
subject to commodity price volatility.  Significant fluctuations in
commodity prices may impact our overall liquidity due to the impact commodity
price changes have on our cash flows from operating activities, including the
impact on working capital for NGLs held in storage, margin requirements and
certain energy-related receivables.  We believe that our available
credit and cash and cash equivalents are adequate to meet liquidity requirements
associated with commodity price volatility.  See discussion beginning
on page 60 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative
Disclosures about Market Risk, for information on our hedging
activities.





ENVIRONMENTAL
LIABILITIES





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




CASH
FLOW ANALYSIS




We use
the indirect method to prepare our Consolidated Statements of Cash
Flows.  Under this method, we reconcile net income to cash flows
provided by operating activities by adjusting net income for those items that
impact net income but may not result in actual cash receipts or payments during
the period.  These reconciling items include depreciation and
amortization, allowance for equity funds used during construction, gain on sale
of assets, minority interests in income of consolidated subsidiaries, and
undistributed earnings from equity investments in excess of distributions
received.





The
following table sets forth the changes in cash flows by operating, investing and
financing activities for the periods indicated.




Variances
                                            
                                            VariancesYears
      Ended December 31,
                                            
                                            
                                            2008
      vs. 2007
                                            
                                            2007
      vs. 20062008
                                            
                                            
                                            2007
                                            
                                            
                                            2006
                                            
                                            
                                            Increase
      (Decrease)
                                            
                                            Increase
      (Decrease)(Millions
      of dollars)Total
      cash provided by (used in):Operating
      activities
                                            $
                                            656.4
                                            
                                            
                                            $
                                            701.5
                                            
                                            
                                            $
                                            603.2
                                            
                                            
                                            $
                                            (45.1
                                            )
                                            
                                            
                                            (6
                                            %)
                                            
                                            $
                                            98.3
                                            
                                            
                                            
                                            16
                                            %Investing
      activities
                                            
                                            (1,246.5
                                            )
                                            
                                            
                                            (1,009.1
                                            )
                                            
                                            
                                            (1,322.1
                                            )
                                            
                                            
                                            (237.4
                                            )
                                            
                                            
                                            (24
                                            %)
                                            
                                            
                                            313.0
                                            
                                            
                                            
                                            24
                                            %Financing
      activities
                                            
                                            764.5
                                            
                                            
                                            
                                            289.7
                                            
                                            
                                            
                                            696.9
                                            
                                            
                                            
                                            474.8
                                            
                                            
                                            
                                            *
                                            
                                            
                                            
                                            (407.2
                                            )
                                            
                                            
                                            (58
                                            %)Change
      in cash and cash equivalents
                                            
                                            174.4
                                            
                                            
                                            
                                            (17.9
                                            )
                                            
                                            
                                            (22.0
                                            )
                                            
                                            
                                            192.3
                                            
                                            
                                            
                                            *
                                            
                                            
                                            
                                            4.1
                                            
                                            
                                            
                                            19
                                            %Cash
      and cash equivalents at beginning of period
                                            
                                            3.2
                                            
                                            
                                            
                                            21.1
                                            
                                            
                                            
                                            43.1
                                            
                                            
                                            
                                            (17.9
                                            )
                                            
                                            
                                            (85
                                            %)
                                            
                                            
                                            (22.0
                                            )
                                            
                                            
                                            (51
                                            %)Cash
      and cash equivalents at end of period
                                            $
                                            177.6
                                            
                                            
                                            $
                                            3.2
                                            
                                            
                                            $
                                            21.1
                                            
                                            
                                            $
                                            174.4
                                            
                                            
                                            
                                            *
                                            
                                            
                                            $
                                            (17.9
                                            )
                                            
                                            
                                            (85
                                            %)*
      Percentage change is greater than 100 percent.





Operating Cash Flows -
Operating cash flows decreased by $45.1 million for 2008, compared with 2007,
primarily due to changes in the components of working capital.  These
changes decreased operating cash flows by $34.6 million, compared with an
increase of $180.3 million for 2007, primarily due to decreases in accounts
payable and increases in derivative financial instruments, partially offset by
decreases in accounts receivable.  Decreased working capital for 2008
was partially offset by higher net income.





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.





Investing Cash Flows -
Investing cash flows for 2008 include increased capital expenditures of $544.0
million, compared with 2007, due to increased spending for our capital
projects.





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


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·
            increased
      capital expenditures of $508.1 million for 2007, compared with 2006, due
      to increased spending for our capital
projects.





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 66-2/3 percent 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;


·
            capital
      expenditures of $201.7 million, 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.





Financing Cash Flows- During
2008, our concurrent public offering and private placement of common units
generated proceeds of $450.2 million.  In addition, ONEOK Partners GP
contributed $9.5 million in order to maintain its 2 percent general partner
interest in us.  We used a portion of the proceeds and general partner
contributions to repay borrowings under our Partnership Credit
Agreement.





During
2007, we completed an underwritten public offering of senior notes totaling $598
million in net proceeds, before offering expenses.  During 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 $770.0 million for 2008, compared with $94.0
million for 2007 and net payments of $200.5 million for 2006.  The
changes between periods occurred for the following reasons.


·
            During
      2008, borrowings under our Partnership Credit Agreement were primarily
      used to fund our ongoing capital projects.  Net borrowings
      include repayments, which were made with a portion of the proceeds
      provided by the public offering and private placement discussed
      above.  Additionally, borrowings increased as a result of our
      decision in late 2008 to borrow under our Partnership Credit Agreement to
      fund our anticipated working capital requirements for the remainder of
      2008 into 2009.


·
            During
      2007, we also used borrowings to fund our ongoing capital
      projects.  The $598 million debt issuance, net of discounts, was
      used to repay borrowings under our 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
      2006, we borrowed $1.05 billion under our $1.1 billion 364-day credit
      facility dated April 6, 2006 (Bridge Facility) to finance a portion of the
      acquisition of the ONEOK Energy Assets and $77 million under our primary
      revolving credit agreement, as then in effect, to acquire the 66-2/3
      percent interest in Guardian Pipeline.  Also, 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.





We
reported cash flows retained by ONEOK of $177.5 million for 2006, which
represented the cash flows generated during the first quarter of 2006 by the
ONEOK Energy Assets prior to the ONEOK Transactions.  See Note B of
the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K for discussion of the ONEOK Transactions.





In March
2006, we borrowed $33 million under our primary revolving credit agreement, as
then in effect, 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 2008 were $453.0 million,
compared with $384.6 million for 2007, an increase of $68.4 million, due the
additional units outstanding during 2008, as a result of the concurrent public
offering and private placement in March and April 2008, as well as increased
distributions per unit.  Cash distributions to our general and limited
partners increased $119.1 million for 2007, compared with 2006, primarily due to
the additional units that were issued to complete the ONEOK Transactions, as
well as increased distributions per unit.  We paid cash distributions
of $4.205 per unit for 2008, compared with $3.98 per unit in 2007 and $3.60 per
unit in 2006.




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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,
2008.  For additional discussion of the debt and operating lease
agreements, see Notes I and J, respectively, of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K.




Payments
      Due by PeriodContractual
      Obligations
                        
                        Total
                        
                        
                        2009
                        
                        
                        2010
                        
                        
                        2011
                        
                        
                        2012
                        
                        
                        2013
                        
                        
                        ThereafterONEOK
      Partners
                        
                        (Thousands
      of dollars)$1
      billion credit agreement
                        
                        $
                        870,000
                        
                        
                        $
                        870,000
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -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
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        450,000Senior
      notes - 6.65%
                        
                        
                        600,000
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        600,000Senior
      notes - 6.85%
                        
                        
                        600,000
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        600,000Guardian
      PipelineSenior
      notes - various
                        
                        
                        121,711
                        
                        
                        
                        11,931
                        
                        
                        
                        11,931
                        
                        
                        
                        11,931
                        
                        
                        
                        11,062
                        
                        
                        
                        7,650
                        
                        
                        
                        67,206Interest
      payments on debt
                        
                        
                        2,686,400
                        
                        
                        
                        176,700
                        
                        
                        
                        163,700
                        
                        
                        
                        140,000
                        
                        
                        
                        120,200
                        
                        
                        
                        114,300
                        
                        
                        
                        1,971,500Operating
      leases
                        
                        
                        86,508
                        
                        
                        
                        18,362
                        
                        
                        
                        16,027
                        
                        
                        
                        15,527
                        
                        
                        
                        8,755
                        
                        
                        
                        2,063
                        
                        
                        
                        25,774Firm
      transportation contracts
                        
                        
                        14,765
                        
                        
                        
                        11,086
                        
                        
                        
                        3,679
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Financial
      and physical derivatives
                        
                        
                        48,467
                        
                        
                        
                        48,467
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Purchase
      commitments,rights
      of way and other
                        
                        
                        35,582
                        
                        
                        
                        30,914
                        
                        
                        
                        977
                        
                        
                        
                        976
                        
                        
                        
                        977
                        
                        
                        
                        977
                        
                        
                        
                        761Total
                        
                        $
                        6,338,433
                        
                        
                        $
                        1,167,460
                        
                        
                        $
                        446,314
                        
                        
                        $
                        393,434
                        
                        
                        $
                        490,994
                        
                        
                        $
                        124,990
                        
                        
                        $
                        3,715,241




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 natural 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, 2008,
associated with our Natural Gas Liquids Gathering and Fractionation
segment.





Purchase Commitments
- Purchase commitments include commitments related to our growth capital
expenditures and other rights 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 Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of
1934, as amended.  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.  We make these
forward-looking statements in reliance on the safe harbor protections provided
under the Private Securities Litigation Reform Act of 1995.  The
following discussion is intended to identify important factors that could cause
future outcomes to differ materially from those set forth in the forward-looking
statements.





Forward-looking
statements include the items identified in the preceding paragraph, the
information concerning possible or assumed future results of our operations and
other statements contained or incorporated in this Annual Report on Form
10-K


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identified
by words such as “anticipate,” “estimate,” “expect,”
“project,”  “intend,” “plan,” “believe,” “should,” “goal,” “forecast,”
“could,” “may,” “continue,” “might,” “potential,” “scheduled” 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, including, but not limited to,
      biofuels such as ethanol and
biodiesel;


·
            the
      capital intensive nature of our
businesses;


·
            the
      profitability of assets or businesses acquired or constructed by
      us;


·
            our
      ability to make cost-saving changes in
  operations;


·
            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, climate change initiatives, authorized rates or recovery of
      gas and gas transportation costs;


·
            the
      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;


·
            difficulties
      or delays experienced by trucks or pipelines in delivering products to or
      from our terminals or pipelines;


·
            changes
      in demand for the use of natural gas because of market conditions caused
      by concerns about global warming;


·
            conflicts
      of interest between us, our general partner, ONEOK Partners GP, and
      related parties of ONEOK Partners
GP;


·
            the
      impact of unforeseen changes in interest rates, equity markets, inflation
      rates, economic recession and other external factors over which we have no
      control;


·
            our
      indebtedness could make us vulnerable to general adverse economic and
      industry conditions, limit our ability to borrow additional funds, and/or
      place us at competitive disadvantages compared to our competitors that
      have less debt or have other adverse
  consequences;


·
            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 that
      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
      effects 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;
  and


-
            availability
      of additional storage capacity;


·
            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 permits, consents and other approvals in
      a timely manner, to promptly obtain all necessary materials and supplies
      required for construction, and to construct gathering, processing,
      storage, fractionation and transportation facilities without labor or
      contractor problems;


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·
            the
      mechanical integrity of facilities
operated;


·
            demand
      for our services in the proximity of our
  facilities;


·
            our
      ability to control operating costs;


·
            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 prolonged slowdown in growth or decline in the U.S. economy or
      the risk of delay in growth recovery in the U.S. economy, including
      increasing liquidity risks in U.S. credit
  markets;


·
            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;


·
            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 NGL marketing
activities to ensure our hedging activities mitigate market risks.  We
do not use financial instruments for trading purposes.





In
accordance with Statement 133, we record derivative instruments at fair
value.  We estimate the fair value of derivative instruments using
available market information and appropriate valuation techniques in accordance
with Statement 157.  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.  At December 31, 2008, the interest rate on
all of our long-term debt was fixed.





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





Total
interest expense savings from amortization of terminated swaps for 2008 were
$3.7 million, compared with total net swap savings of $2.5 million in
2007.  Total swap savings from terminated swaps for 2009 are expected
to be $3.7 million.




COMMODITY
PRICE RISK




In our
Natural Gas Gathering and Processing segment, we are 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.  We are also exposed
to the risk of price fluctuations and the cost of intervening transportation at
various market locations.  As part of our hedging strategy, 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, 2009.





Year
      Ending December 31, 2009Volumes
                                                              Hedged
                                                            Average
      Price
                                                            Percentage
                                                              HedgedNGLs
      (Bbl/d)(a)
                                                            
                                                            
                                                            5,010
                                                            
                                                            
                                                            
                                                            $
                                                            1.18
                                                            
                                                            /
      gallon
                                                            57%Condensate
      (Bbl/d)(a)
                                                            
                                                            
                                                            666
                                                            
                                                            
                                                            
                                                            $
                                                            3.23
                                                            
                                                            /
      gallon
                                                            32%Total
      sales hedged (Bbl/d)
                                                            
                                                            
                                                            5,676
                                                            
                                                            
                                                            
                                                            $
                                                            1.42
                                                            
                                                            /
      gallon
                                                            52%(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, 2008, 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 decrease in the composite price of NGLs would decrease
      annual net margin by approximately $1.2
million;


·
            a
      $1.00 per barrel decrease in the price of crude oil would decrease annual
      net margin by approximately $1.0 million;
and


·
            a
      $0.10 per MMBtu decrease in the price of natural gas would decrease annual
      net margin by approximately $0.6
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 a change in the amount of ethane extracted from the natural gas stream,
impacting gathering and processing margins, NGL exchange revenues, natural gas
deliveries, and NGL volumes shipped and fractionated.





In our
Natural Gas Liquids Gathering and Fractionation segment, we are exposed to
commodity price risk primarily as a result of NGLs in storage, the relative
values of the various NGL products to each other, the relative value of NGLs to
natural gas and the relative value of NGL purchases at one location and sales at
another location, known as basis risk.  We utilize


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fixed-price
physical forward contracts to reduce earnings volatility related to NGL price
fluctuations.  We have not entered into any financial instruments with
respect to our NGL marketing activities.





In our
Natural Gas Pipelines segment, we are exposed to commodity price risk because
our intrastate and interstate natural gas pipelines collect natural gas from our
customers for operations or as part of our fee for services
provided.  When the amount of natural gas consumed in operations by
these pipelines differs from the amount provided by our 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, 2008, there were
no hedges in place with respect to natural gas price risk from our intrastate
and interstate pipeline operations.





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





COUNTERPARTY
CREDIT RISK





We assess
the creditworthiness of our counterparties on an on-going basis and require
security, including prepayments and other forms of cash collateral, when
appropriate.




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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 sheets and the related
consolidated statements 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, 2008
and 2007, and the results of their operations and their cash flows for each of
the two years ended December 31, 2008,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, 2008, 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, 2008.  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
24, 2009


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 statement of income, cash flows, and
changes in partners’ equity and comprehensive income of ONEOK Partners, L.P. and
subsidiaries (the Partnership) (formerly Northern Border Partners, L.P.) for the
year ended December 31, 2006.  The 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 audit.





We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
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 audit provides a reasonable basis
for our opinion.





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





/s/ KPMG
LLP


Tulsa,
Oklahoma


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




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intentionally left blank.






















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ONEOK
      Partners, L.P. and SubsidiariesCONSOLIDATED
      STATEMENTS OF INCOMEYears
      Ended December 31,2008
                      
                      
                      2007
                      
                      
                      2006(Thousands
      of dollars, except per unit amounts)Revenues
                      
                      $
                      7,720,206
                      
                      
                      $
                      5,831,558
                      
                      
                      $
                      4,738,248Cost
      of sales and fuel
                      
                      
                      6,579,547
                      
                      
                      
                      4,935,665
                      
                      
                      
                      3,894,700Net
      Margin
                      
                      
                      1,140,659
                      
                      
                      
                      895,893
                      
                      
                      
                      843,548Operating
      ExpensesOperations
      and maintenance
                      
                      
                      337,526
                      
                      
                      
                      302,544
                      
                      
                      
                      294,207Depreciation
      and amortization
                      
                      
                      124,765
                      
                      
                      
                      113,704
                      
                      
                      
                      122,045General
      taxes
                      
                      
                      34,271
                      
                      
                      
                      34,812
                      
                      
                      
                      31,567Total
      Operating Expenses
                      
                      
                      496,562
                      
                      
                      
                      451,060
                      
                      
                      
                      447,819Gain
      (Loss) on Sale of Assets
                      
                      
                      713
                      
                      
                      
                      1,950
                      
                      
                      
                      115,483Operating
      Income
                      
                      
                      644,810
                      
                      
                      
                      446,783
                      
                      
                      
                      511,212Equity
      earnings from investments (Note M)
                      
                      
                      101,432
                      
                      
                      
                      89,908
                      
                      
                      
                      95,883Allowance
      for equity funds used during construction
                      
                      
                      50,906
                      
                      
                      
                      12,538
                      
                      
                      
                      2,205Other
      income
                      
                      
                      5,621
                      
                      
                      
                      7,502
                      
                      
                      
                      6,510Other
      expense
                      
                      
                      (13,321
                      )
                      
                      
                      (779
                      )
                      
                      
                      (7,081
                      )Interest
      expense
                      
                      
                      (151,056
                      )
                      
                      
                      (138,947
                      )
                      
                      
                      (133,482
                      )Income
      before Minority Interests and Income Taxes
                      
                      
                      638,392
                      
                      
                      
                      417,005
                      
                      
                      
                      475,247Minority
      interests in income of consolidated subsidiaries
                      
                      
                      (441
                      )
                      
                      
                      (416
                      )
                      
                      
                      (2,392
                      )Income
      taxes (Note K)
                      
                      
                      (12,335
                      )
                      
                      
                      (8,842
                      )
                      
                      
                      (27,669
                      )Net
      Income
                      
                      $
                      625,616
                      
                      
                      $
                      407,747
                      
                      
                      $
                      445,186Limited
      partners’ interest in net income:Net
      income
                      
                      $
                      625,616
                      
                      
                      $
                      407,747
                      
                      
                      $
                      445,186General
      partner’s interest in net income
                      
                      
                      (88,554
                      )
                      
                      
                      (58,781
                      )
                      
                      
                      (75,654
                      )Limited
      Partners’ Interest in Net Income
                      
                      $
                      537,062
                      
                      
                      $
                      348,966
                      
                      
                      $
                      369,532Limited
      partners’ per unit net income (Note N)
                      
                      $
                      6.01
                      
                      
                      $
                      4.21
                      
                      
                      $
                      5.01Number
      of Units Used in Computation  (Thousands)
                      
                      
                      89,309
                      
                      
                      
                      82,891
                      
                      
                      
                      73,768See
      accompanying Notes to Consolidated Financial Statements.


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ONEOK
      Partners, L.P. and SubsidiariesCONSOLIDATED
      BALANCE SHEETS
                            
                            December
      31,
                            
                            
                            December
      31,2008
                            
                            
                            2007Assets
                            
                            (Thousands
      of dollars)Current
      AssetsCash
      and cash equivalents
                            
                            $
                            177,635
                            
                            
                            $
                            3,213Accounts
      receivable, net
                            
                            
                            317,182
                            
                            
                            
                            577,989Affiliate
      receivables
                            
                            
                            25,776
                            
                            
                            
                            52,479Gas
      and natural gas liquids in storage
                            
                            
                            190,616
                            
                            
                            
                            251,219Commodity
      exchanges and imbalances
                            
                            
                            55,086
                            
                            
                            
                            82,037Derivative
      financial instruments (Notes C and D)
                            
                            
                            63,780
                            
                            
                            
                            -Other
      current assets
                            
                            
                            28,176
                            
                            
                            
                            19,961Total
      Current Assets
                            
                            
                            858,251
                            
                            
                            
                            986,898Property,
      Plant and EquipmentProperty,
      plant and equipment
                            
                            
                            5,808,679
                            
                            
                            
                            4,436,371Accumulated
      depreciation and amortization
                            
                            
                            875,279
                            
                            
                            
                            776,185Net
      Property, Plant and Equipment (Note A)
                            
                            
                            4,933,400
                            
                            
                            
                            3,660,186Investments
      and Other AssetsInvestments
      in unconsolidated affiliates (Note M)
                            
                            
                            755,492
                            
                            
                            
                            756,260Goodwill
      and intangible assets (Note E)
                            
                            
                            676,536
                            
                            
                            
                            682,084Other
      assets
                            
                            
                            30,593
                            
                            
                            
                            26,637Total
      Investments and Other Assets
                            
                            
                            1,462,621
                            
                            
                            
                            1,464,981Total
      Assets
                            
                            $
                            7,254,272
                            
                            
                            $
                            6,112,065Liabilities
      and Partners’ EquityCurrent
      LiabilitiesCurrent
      maturities of long-term debt (Note I)
                            
                            $
                            11,931
                            
                            
                            $
                            11,930Notes
      payable
                            
                            
                            870,000
                            
                            
                            
                            100,000Accounts
      payable
                            
                            
                            496,763
                            
                            
                            
                            742,903Affiliate
      payables
                            
                            
                            23,333
                            
                            
                            
                            18,298Commodity
      exchanges and imbalances
                            
                            
                            191,165
                            
                            
                            
                            252,095Other
      current liabilities
                            
                            
                            100,832
                            
                            
                            
                            136,664Total
      Current Liabilities
                            
                            
                            1,694,024
                            
                            
                            
                            1,261,890Long-term
      Debt, excluding current maturities (Note I)
                            
                            
                            2,589,509
                            
                            
                            
                            2,605,396Deferred
      Credits and Other Liabilities
                            
                            
                            54,773
                            
                            
                            
                            43,799Commitments
      and Contingencies (Note J)Minority
      Interests in Consolidated Subsidiaries
                            
                            
                            5,941
                            
                            
                            
                            5,802Partners’
      EquityGeneral
      partner
                            
                            
                            77,546
                            
                            
                            
                            58,415Common
      units: 54,426,087 units and 46,397,214 units
                              issued
      and outstanding at December 31, 2008 and
                              2007,
      respectively
                            
                            
                            1,361,058
                            
                            
                            
                            814,266Class
      B units: 36,494,126 units issued and outstanding at
                              December
      31, 2008 and 2007
                            
                            
                            1,407,016
                            
                            
                            
                            1,340,638Accumulated
      other comprehensive income (loss) (Note F)
                            
                            
                            64,405
                            
                            
                            
                            (18,141
                            )Total
      Partners’ Equity
                            
                            
                            2,910,025
                            
                            
                            
                            2,195,178Total
      Liabilities and Partners’ Equity
                            
                            $
                            7,254,272
                            
                            
                            $
                            6,112,065See
      accompanying Notes to Consolidated Financial Statements.




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ONEOK
      Partners, L.P. and SubsidiariesCONSOLIDATED
      STATEMENTS OF CASH FLOWS
                        
                        Years
      Ended December 31,2008
                        
                        
                        2007
                        
                        
                        2006(Thousands
      of dollars)Operating
      ActivitiesNet
      income
                        
                        $
                        625,616
                        
                        
                        $
                        407,747
                        
                        
                        $
                        445,186Depreciation
      and amortization
                        
                        
                        124,765
                        
                        
                        
                        113,704
                        
                        
                        
                        122,045Allowance
      for equity funds used during construction
                        
                        
                        (50,906
                        )
                        
                        
                        (12,538
                        )
                        
                        
                        (2,205
                        )Gain
      on sale of assets
                        
                        
                        (713
                        )
                        
                        
                        (1,950
                        )
                        
                        
                        (115,483
                        )Minority
      interests in income of consolidated subsidiaries
                        
                        
                        441
                        
                        
                        
                        416
                        
                        
                        
                        2,392Equity
      earnings from investments
                        
                        
                        (101,432
                        )
                        
                        
                        (89,908
                        )
                        
                        
                        (95,883
                        )Distributions
      received from unconsolidated affiliates
                        
                        
                        93,261
                        
                        
                        
                        103,785
                        
                        
                        
                        123,427Changes
      in assets and liabilities (net of acquisition and disposition
      effects):Accounts
      receivable
                        
                        
                        256,137
                        
                        
                        
                        (268,963
                        )
                        
                        
                        129,323Affiliate
      receivables
                        
                        
                        26,703
                        
                        
                        
                        36,093
                        
                        
                        
                        (87,175
                        )Gas
      and natural gas liquids in storage
                        
                        
                        16,003
                        
                        
                        
                        (47,973
                        )
                        
                        
                        24,933Derivative
      financial instruments
                        
                        
                        (2,538
                        )
                        
                        
                        2,154
                        
                        
                        
                        (2,154
                        )Accounts
      payable
                        
                        
                        (273,475
                        )
                        
                        
                        368,452
                        
                        
                        
                        (10,960
                        )Affiliate
      payables
                        
                        
                        5,035
                        
                        
                        
                        (7,439
                        )
                        
                        
                        18,657Commodity
      exchanges and imbalances, net
                        
                        
                        (33,979
                        )
                        
                        
                        41,997
                        
                        
                        
                        20,129Accrued
      interest
                        
                        
                        5,669
                        
                        
                        
                        9,069
                        
                        
                        
                        23,445Other
      assets and liabilities
                        
                        
                        (34,169
                        )
                        
                        
                        46,888
                        
                        
                        
                        7,541Cash
      Provided by Operating Activities
                        
                        
                        656,418
                        
                        
                        
                        701,534
                        
                        
                        
                        603,218Investing
      ActivitiesChanges
      in investments in unconsolidated affiliates
                        
                        
                        3,963
                        
                        
                        
                        (3,668
                        )
                        
                        
                        (6,608
                        )Acquisitions
                        
                        
                        2,450
                        
                        
                        
                        (299,560
                        )
                        
                        
                        (1,396,893
                        )Capital
      expenditures (less allowance for equity funds used during
      construction)
                        
                        
                        (1,253,853
                        )
                        
                        
                        (709,858
                        )
                        
                        
                        (201,746
                        )Proceeds
      from sale of assets
                        
                        
                        990
                        
                        
                        
                        3,980
                        
                        
                        
                        297,674Increase
      in cash and cash equivalents attributable to previouslyunconsolidated
      subsidiaries
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        7,496Decrease
      in cash and cash equivalents attributable to previouslyconsolidated
      subsidiaries
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        (22,039
                        )Cash
      Used in Investing Activities
                        
                        
                        (1,246,450
                        )
                        
                        
                        (1,009,106
                        )
                        
                        
                        (1,322,116
                        )Financing
      ActivitiesCash
      distributions:General
      and limited partners
                        
                        
                        (453,021
                        )
                        
                        
                        (384,646
                        )
                        
                        
                        (265,479
                        )Minority
      interests
                        
                        
                        (302
                        )
                        
                        
                        (220
                        )
                        
                        
                        (343
                        )Cash
      flow retained by ONEOK (Note B)
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        (177,486
                        )Borrowing
      (repayment) of notes payable, net
                        
                        
                        (100,000
                        )
                        
                        
                        94,000
                        
                        
                        
                        (200,500
                        )Borrowing
      of notes payable with maturities over 90 days
                        
                        
                        870,000
                        
                        
                        
                        -
                        
                        
                        
                        -Issuance
      of long-term debt, net of discounts
                        
                        
                        -
                        
                        
                        
                        598,146
                        
                        
                        
                        1,397,327Long-term
      debt financing costs
                        
                        
                        -
                        
                        
                        
                        (5,805
                        )
                        
                        
                        (12,003
                        )Issuance
      of common units, net of discounts
                        
                        
                        450,198
                        
                        
                        
                        -
                        
                        
                        
                        -Contributions
      from general partner
                        
                        
                        9,508
                        
                        
                        
                        -
                        
                        
                        
                        -Payment
      of long-term debt
                        
                        
                        (11,929
                        )
                        
                        
                        (11,931
                        )
                        
                        
                        (40,978
                        )Other
      financing activities
                        
                        
                        -
                        
                        
                        
                        139
                        
                        
                        
                        (3,628
                        )Cash
      Provided by Financing Activities
                        
                        
                        764,454
                        
                        
                        
                        289,683
                        
                        
                        
                        696,910Change
      in Cash and Cash Equivalents
                        
                        
                        174,422
                        
                        
                        
                        (17,889
                        )
                        
                        
                        (21,988
                        )Cash
      and Cash Equivalents at Beginning of Period
                        
                        
                        3,213
                        
                        
                        
                        21,102
                        
                        
                        
                        43,090Cash
      and Cash Equivalents at End of Period
                        
                        $
                        177,635
                        
                        
                        $
                        3,213
                        
                        
                        $
                        21,102Supplemental
      Cash Flow Information:Cash
      Paid for Interest
                        
                        $
                        148,417
                        
                        
                        $
                        138,606
                        
                        
                        $
                        86,290Cash
      Paid for Taxes
                        
                        $
                        4,722
                        
                        
                        $
                        1,039
                        
                        
                        $
                        610See
      accompanying Notes to Consolidated Financial Statements.


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ONEOK
      Partners, L.P. and SubsidiariesCONSOLIDATED
      STATEMENT OF CHANGES IN PARTNERS’ EQUITY AND COMPREHENSIVE
      INCOMECommon
                            Units
                          
                          
                          Class
      B
                            Units
                          
                          
                          General
                            Partner
                          
                          
                          Common
                            Units(Units)
                          
                          
                          (Thousands
      of dollars)December
      31, 2005
                          
                          
                          46,397,214
                          
                          
                          
                          -
                          
                          
                          $
                          17,341
                          
                          
                          $
                          750,201Net
      income
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          75,654
                          
                          
                          
                          220,428Other
      comprehensive income (loss)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Total
      comprehensive incomeNet
      Income retained by ONEOK (Note B)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (35,818
                          )
                          
                          
                          -Issuance
      of Class B units andcontribution
      from general partner
                          
                          
                          -
                          
                          
                          
                          36,494,126
                          
                          
                          
                          25,576
                          
                          
                          
                          -Distributions
      paid (Note N)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (28,380
                          )
                          
                          
                          (167,030
                          )December
      31, 2006
                          
                          
                          46,397,214
                          
                          
                          
                          36,494,126
                          
                          
                          
                          54,373
                          
                          
                          
                          803,599Net
      income
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          58,781
                          
                          
                          
                          195,329Other
      comprehensive income (loss) (Note F)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Total
      comprehensive incomeOther
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (1
                          )
                          
                          
                          -Distributions
      paid (Note N)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (54,738
                          )
                          
                          
                          (184,662
                          )December
      31, 2007
                          
                          
                          46,397,214
                          
                          
                          
                          36,494,126
                          
                          
                          
                          58,415
                          
                          
                          
                          814,266Net
      income
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          88,554
                          
                          
                          
                          317,226Other
      comprehensive income (loss) (Note F)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Total
      comprehensive incomeIssuance
      of common units (Note G)
                          
                          
                          8,028,873
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          450,198Contribution
      from general partner (Note G)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          9,508
                          
                          
                          
                          -Distributions
      paid (Note N)
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (78,931
                          )
                          
                          
                          (220,632
                          )December
      31, 2008
                          
                          
                          54,426,087
                          
                          
                          
                          36,494,126
                          
                          
                          $
                          77,546
                          
                          
                          $
                          1,361,058See
      accompanying Notes to Consolidated Financial Statements.


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ONEOK
      Partners, L.P. and SubsidiariesCONSOLIDATED
      STATEMENT OF CHANGES IN PARTNERS’ EQUITY AND COMPREHENSIVE
      INCOME(Continued)Accumulated
      Other Comprehensive Income (Loss)Total
      Partners’ EquityClass
      B
                                                                    Units(Thousands
      of dollars)December
      31, 2005
                                                                  
                                                                  $
                                                                  -
                                                                  
                                                                  
                                                                  $
                                                                  (1,953
                                                                  )
                                                                  
                                                                  $
                                                                  765,589Net
      income
                                                                  
                                                                  
                                                                  149,104
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  445,186Other
      comprehensive income (loss)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  367
                                                                  
                                                                  
                                                                  
                                                                  367Total
      comprehensive income
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  445,553Net
      Income retained by ONEOK (Note B)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (35,818
                                                                  )Issuance
      of Class B units andcontribution
      from general partner
                                                                  
                                                                  
                                                                  1,253,241
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  1,278,817Distributions
      paid (Note N)
                                                                  
                                                                  
                                                                  (70,069
                                                                  )
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (265,479
                                                                  )December
      31, 2006
                                                                  
                                                                  
                                                                  1,332,276
                                                                  
                                                                  
                                                                  
                                                                  (1,586
                                                                  )
                                                                  
                                                                  
                                                                  2,188,662Net
      income
                                                                  
                                                                  
                                                                  153,637
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  407,747Other
      comprehensive income (loss) (Note F)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (16,555
                                                                  )
                                                                  
                                                                  
                                                                  (16,555
                                                                  )Total
      comprehensive income
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  391,192Other
                                                                  
                                                                  
                                                                  (29
                                                                  )
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (30
                                                                  )Distributions
      paid (Note N)
                                                                  
                                                                  
                                                                  (145,246
                                                                  )
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (384,646
                                                                  )December
      31, 2007
                                                                  
                                                                  
                                                                  1,340,638
                                                                  
                                                                  
                                                                  
                                                                  (18,141
                                                                  )
                                                                  
                                                                  
                                                                  2,195,178Net
      income
                                                                  
                                                                  
                                                                  219,836
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  625,616Other
      comprehensive income (loss) (Note F)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  82,546
                                                                  
                                                                  
                                                                  
                                                                  82,546Total
      comprehensive income
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  
                                                                  708,162Issuance
      of common units (Note G)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  450,198Contribution
      from general partner (Note G)
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  9,508Distributions
      paid (Note N)
                                                                  
                                                                  
                                                                  (153,458
                                                                  )
                                                                  
                                                                  
                                                                  -
                                                                  
                                                                  
                                                                  
                                                                  (453,021
                                                                  )December
      31, 2008
                                                                  
                                                                  $
                                                                  1,407,016
                                                                  
                                                                  
                                                                  $
                                                                  64,405
                                                                  
                                                                  
                                                                  $
                                                                  2,910,025




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ONEOK
PARTNERS, L.P. AND SUBSIDIARIES


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS





A.              SUMMARY
OF ACCOUNTING POLICIES





Organization and Nature of
Operations - ONEOK Partners, L.P. is a publicly traded Delaware master
limited partnership that was formed in 1993.  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.   We are managed under the
direction of the Board of Directors of our sole general partner, ONEOK Partners
GP.  ONEOK Partners GP is a wholly owned subsidiary of
ONEOK.  ONEOK owns a 47.7 percent aggregate equity interest in
us.





Our
operations include gathering of unprocessed natural gas produced from crude oil
and natural gas wells.  We gather unprocessed 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
unprocessed natural gas in two producing basins in the Rocky Mountain region:
the Williston Basin, which spans portions of Montana, North Dakota and the
Canadian province of Saskatchewan, and the Powder River Basin of
Wyoming.





Our
interstate natural gas pipeline assets transport natural gas through
FERC-regulated interstate natural gas pipelines in Montana, North Dakota, South
Dakota, Minnesota, Wisconsin, Iowa, Illinois, Indiana, Kentucky, Tennessee,
Oklahoma, Texas and New Mexico.  Our interstate pipelines include
Midwestern Gas Transmission, Viking Gas Transmission, Guardian Pipeline and
OkTex Pipeline.  Midwestern Gas Transmission is a bi-directional
system that interconnects with Tennessee Gas Transmission Company near Portland,
Tennessee, and with several interstate pipelines near Joliet,
Illinois.  Viking Gas Transmission transports natural gas from an
interconnection with TransCanada near Emerson, Manitoba, to an interconnection
with ANR Pipeline Company near Marshfield, Wisconsin.  Guardian
Pipeline interconnects with several pipelines in Joliet, Illinois, and with
local distribution companies in 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.  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 storage capacity in underground natural gas storage
facilities in Oklahoma, Kansas and Texas.  Our natural gas pipelines
primarily serve local distribution companies, large industrial companies,
municipalities, irrigation customers, power generation facilities and marketing
companies.





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 and NGL
products in Mont Belvieu, Texas.  Most of the pipeline-connected
natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which
extract NGLs from unprocessed natural gas, are connected to our gathering
systems.  The natural gas liquids pipelines 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 our customers, such as petrochemical manufacturers, heating fuel users,
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.  We also purchase NGLs and condensate from third parties, as
well as from our Natural Gas Gathering and Processing segment.





We own
and operate 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, the Texas panhandle and the Rocky Mountain region to our
Natural Gas Liquids Gathering and Fractionation segment’s Mid-Continent
fractionation facilities in Oklahoma and Kansas.  Our natural gas
liquids distribution pipelines deliver unfractionated NGLs and 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 Energy Partners, L.P. (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, including Chicago, Illinois.  We operate FERC-regulated natural
gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Nebraska,
Missouri, Iowa, Illinois, Indiana, Texas, Wyoming and Colorado.  We have
product terminal and storage facilities in Missouri, Nebraska, Iowa and
Illinois.


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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 our management’s most
difficult, subjective or complex judgment, particularly because of the need to
make estimates concerning the impact of inherently uncertain
matters.  We have discussed the development and selection of our
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 for impairment at least annually based on Statement 142, “Goodwill
and Other Intangible Assets.”  There were no impairment charges
resulting from our July 1, 2008, impairment test.  As a result of
recent events in the financial markets and current economic conditions, we
performed a review and determined that interim testing of goodwill as of
December 31, 2008, was not necessary.  As part of our impairment test,
an initial assessment is made by comparing the fair value of a reporting unit
with its book value, including goodwill.  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 reporting unit from the fair value
determined in step one of the assessment.  If the carrying value of
the goodwill exceeds the implied fair value of the goodwill, we will record an
impairment charge.





We use
two generally accepted valuation approaches, an income approach and a market
approach, to estimate the fair value of a reporting unit.  Under the
income approach, we use anticipated cash flows over a three-year period plus a
terminal value and discount these amounts to their present value using
appropriate rates of return.  Under the market approach, we apply
multiples to forecasted EBITDA amounts.  The multiples used are
consistent with historical asset transactions, and the EBITDA amounts are based
on average EBITDA for a reporting unit over a three-year forecasted
period.  See Note E for more discussion of goodwill.





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





Our
impairment tests require the use of assumptions and estimates.  If
actual results are not consistent with our assumptions and estimates or our
assumptions and estimates change due to new information, we may be exposed to an
impairment charge.





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 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, with the exception of normal purchases and normal sales that are expected
to result in physical delivery.  See Note C for additional fair value
discussion.  Market value changes result in a change in the fair value
of our derivative instruments.  The accounting for changes in the fair
value of a derivative instrument depends on whether it has been designated and
qualifies as part of a hedging relationship and, if so, the nature of the risk
being hedged and how we will determine if the hedging instrument is
effective.  If the derivative instrument does not qualify or is not
designated as part of a hedging relationship, then we account for changes in
fair value of the derivative in earnings as they occur.  Commodity
price volatility may have a significant impact on the gain or loss in a given
period.


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





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





See Note
D 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.  Accruals for
estimated losses from environmental remediation obligations generally are
recognized no later than completion of the remediation feasibility
study.  Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed
probable.  Actual results may differ from our estimates resulting in
an impact, positive or negative, on earnings.  See Note J 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.





Use of Estimates - The
preparation of our consolidated financial statements and related disclosures in
accordance with GAAP requires us to make estimates and assumptions with respect
to values or conditions that cannot be known with certainty that affect the
reported amount of assets and liabilities, and the disclosure of contingent
assets and liabilities at the date of the consolidated financial
statements.  These estimates and assumptions also affect the reported
amounts of revenue and expenses during the reporting period.  Items
that may be estimated include, but are not limited to, the economic useful life
of assets, fair value of assets and liabilities, 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.





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.





Accounts Receivable, net -
Accounts receivable represent valid claims against non-affiliated customers for
products sold or services rendered, net of allowances for doubtful
accounts.  We assess the creditworthiness of our counterparties on an
on-going basis and require security, including prepayments and other forms of
cash collateral, when appropriate.  Outstanding customer receivables
are regularly reviewed for possible non-payment indicators and allowances for
doubtful accounts are recorded based upon management’s estimate of
collectibility at each balance sheet date.





Inventory, Natural Gas Imbalances and
Commodity Exchanges -Inventory held for sale
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
weighted-average cost or market method.  Noncurrent natural gas and
NGLs are 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


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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.





Property, Plant and Equipment-The
following table sets forth our property, plant and equipment by segment, for the
periods presented.




December
      31,
                    
                    
                    December
      31,2008
                    
                    
                    2007(Thousands
      of dollars)Non-RegulatedNatural
      Gas Gathering and Processing
                    
                    $
                    1,368,223
                    
                    
                    $
                    1,227,475Natural
      Gas Pipelines
                    
                    
                    167,625
                    
                    
                    
                    162,390Natural
      Gas Liquids Gathering and Fractionation
                    
                    
                    879,047
                    
                    
                    
                    672,047Other
                    
                    
                    50,474
                    
                    
                    
                    50,482RegulatedNatural
      Gas Pipelines
                    
                    
                    1,460,764
                    
                    
                    
                    1,184,112Natural
      Gas Liquids Pipelines
                    
                    
                    1,882,546
                    
                    
                    
                    1,139,865Property,
      plant and equipment
                    
                    
                    5,808,679
                    
                    
                    
                    4,436,371Accumulated
      depreciation and amortization
                    
                    
                    875,279
                    
                    
                    
                    776,185Net
      property, plant and equipment
                    
                    $
                    4,933,400
                    
                    
                    $
                    3,660,186





Our
properties are stated at cost which includes AFUDC.  Generally, the
cost of regulated property retired or sold, plus removal costs, less salvage, is
charged to accumulated depreciation.  Gains and losses from sales or
transfers of non-regulated properties or an entire operating unit or system of
our regulated properties are recognized in income.  Maintenance and
repairs are charged directly to expense.





The
interest portion of AFUDC represents the cost of borrowed funds used to finance
construction activities.  We capitalize interest expense during the
construction or upgrade of qualifying assets.  Interest expense
capitalized in 2008, 2007 and 2006 was $36.1 million, $13.6 million and $1.2
million, respectively.  Capitalized interest is recorded as a
reduction to interest expense.  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 in the cost of our regulated
properties and as a credit to the allowance for equity funds used during
construction.





Our
properties are depreciated using the straight-line method over their estimated
useful lives.  Generally, we apply composite depreciation rates to
functional groups of property having similar economic
circumstances.  We periodically conduct depreciation studies to assess
the economic lives of our assets.  For our regulated assets, these
deprecation studies are completed as a part of our rate proceedings, and the
changes in economic lives, if applicable, are implemented prospectively when the
new rates are billed.  For our non-regulated assets, if it is determined
that the estimated economic life changes, then the changes are made
prospectively.  Changes in the estimated economic lives of our property,
plant and equipment could have a material effect on our financial position or
result of operations.





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
                          
                          2008
                          
                          
                          2007
                          
                          
                          2006Natural
      Gas Pipelines
                          
                          
                          2.4%
                          
                          
                          
                          2.4%
                          
                          
                          
                          2.4%Natural
      Gas Liquids Pipelines
                          
                          
                          2.0%
                          
                          
                          
                          2.5%
                          
                          
                          
                          2.6%





The
average depreciation rate for our Natural Gas Liquids Pipelines segment’s
regulated property decreased in 2008, compared with 2007, due to placing newly
constructed assets with longer economic lives in service.





At
December 31, 2008 and 2007, property, plant and equipment on our Consolidated
Balance Sheets included construction work in progress of $810.0 million and
$859.8 million, respectively, that had not yet been put in service and therefore
was not being depreciated.  Assets are transferred out of construction
work in process when they are substantially complete and ready for their
intended use, in accordance with Statement 34, “Capitalization of Interest
Cost.”


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





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





Our
corporate subsidiaries are required to pay federal and state income
taxes.  Income taxes are accounted for 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, “Accounting for the Effects of Certain Types of Regulation,”
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 was effective for our year
beginning January 1, 2007.  This interpretation was issued to clarify
the accounting for uncertainty in income taxes recognized in the financial
statements by prescribing a recognition threshold and measurement attribute for
the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return.  FIN 48 requires the recognition
of penalties and interest on any unrecognized tax benefits.  Our
policy is to reflect penalties and interest as part of income tax expense as
they become applicable.  During 2008 and 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.





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.  In Kansas and Texas, natural gas storage may be regulated by
the state and the FERC for certain types of services.  Accordingly,
portions of our Natural Gas Pipelines segment and Natural Gas Liquids Pipelines
segment follow the accounting and reporting guidance contained in Statement
71.  During the rate-making process, regulatory authorities set the
framework for what we can charge customers for our services and establish the
manner that our costs are accounted for, including allowing us to defer
recognition of certain costs and permitting recovery of the amounts through
rates over time as opposed to expensing such costs as
incurred.  Certain examples of types of regulatory guidance include
costs for fuel and losses, acquisition costs, contributions in aid of
construction, charges for depreciation, and gains or losses on disposition of
assets.  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 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, 2008 and 2007, we recorded regulatory assets of approximately $12.8
million and $6.8 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


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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.





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, “Effective Date of FASB Statement No. 157,” which delayed the effective
date of Statement 157 for nonrecurring fair value measurements associated with
our nonfinancial assets and liabilities.  As of January 1, 2008, we
have applied the provisions of Statement 157 to our recurring fair value
measurements, and the impact was not material.  See Note C for
disclosures of fair value measurements for our financial
instruments.  As of January 1, 2009, we have applied the provisions of
Statement 157 to our nonrecurring fair value measurements associated with our
nonfinancial assets and liabilities, and the impact was not
material.  FSP 157-3, “Determining the Fair Value of a Financial Asset
When the Market for That Asset Is Not Active,” which clarified the application
of Statement 157 in inactive markets, was issued in October 2008 and was
effective for our September 30, 2008, unaudited consolidated financial
statements.  FSP 157-3 did not have a material 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 on our
consolidated financial statements.





Master Netting Arrangement -
In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation
No. 39,” which requires entities that offset the fair value amounts recognized
for derivative receivables and payables to also offset the fair value amounts
recognized for the right to reclaim cash collateral with the same counterparty
under a master netting arrangement.  We applied the provisions of FIN
39-1 to our consolidated financial statements beginning January 1, 2008, and the
impact was not material.  At December 31, 2008, we had no cash
collateral held or posted under our master netting arrangement.





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 interest) and goodwill acquired in a
business combination to be recorded at fair value.  Statement 141R was
effective for our year beginning January 1, 2009.  Because the
provisions of Statement 141R are applied prospectively, our 2009 and subsequent
consolidated financial statements will not be impacted unless we complete a
business combination.





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 interest (previously referred to as minority interest) to be
reported as a component of equity.  Statement 160 was effective for
our year beginning January 1, 2009, and requires retroactive adoption of the
presentation and disclosure requirements for existing minority interests
beginning with our March 31, 2009, Quarterly Report on Form
10-Q.  Statement 160 is not expected to have a material impact on our
consolidated financial statements; however, certain financial statement
presentation changes and additional required disclosures will be
made.





Equity Method Investments - In
November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting
Considerations,” which clarified certain issues that arose following the
issuance of Statements 141R and 160 related to the accounting for equity method
investments.  EITF 08-6 was effective for our year beginning January
1, 2009, and is not expected to have a material impact on our consolidated
financial statements.


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Derivative Instruments and Hedging
Activities Disclosure - In March 2008, the FASB issued Statement 161,
“Disclosures about Derivative Instruments and Hedging Activities - an amendment
to FASB Statement No. 133,” which required enhanced disclosures about how
derivative and hedging activities affect our financial position, financial
performance and cash flows.  Statement 161 was effective for our year
beginning January 1, 2009, and will be applied prospectively beginning with our
March 31, 2009, Quarterly Report on Form 10-Q.





Net Income Per Unit - The FASB
ratified EITF 07-4, “Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships,” in March 2008.  EITF 07-4 results
in the allocation of undistributed current-period earnings to the unitholders
using the two-class method in periods in which earnings exceed
distributions.  When distributions to participating securities exceed
current-period earnings, the excess distributions generate an undistributed loss
that would be allocated back to the equity interests based on the contractual
terms of the partnership agreement.  EITF 07-4 was effective for our year
beginning January 1, 2009, and requires retrospective application beginning with
our March 31, 2009, Quarterly Report on Form 10-Q.  Application of EITF
07-4 will impact our net income-per-unit disclosure but will have no impact on
our financial position, results of operations or cash flows.





Reclassifications - Certain
amounts in our consolidated financial statements have been reclassified to
conform to the 2008 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 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 products and refined petroleum products.  The FERC-regulated
system spans 1,624 miles and has a capacity to transport up to 134
MBbl/d.  The transaction also included 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 Heartland, which consists primarily of a refined
petroleum products terminal and pipelines with access to two other refined
petroleum product terminals.  Our investment in Heartland is accounted
for under the equity method of accounting.  Financing for this
transaction came from a portion of the proceeds of our September 2007 issuance
of $600 million 6.85 percent Senior Notes due 2037 (the 2037
Notes).  See Note I for a discussion of the 2037 Notes.  The
working capital settlement was finalized in April 2008, with no 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.  In November 2008, Overland Pass Pipeline Company completed
construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to
the Mid-Continent natural gas liquids market center in Conway,
Kansas.  The Overland Pass Pipeline is designed to transport
approximately 110 MBbl/d of unfractionated NGLs and can be increased to
approximately 255 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.  Initially, as the 99 percent owner of the joint
venture, we managed the construction project and advanced all costs associated
with construction.  We are currently operating the
pipeline.  On or before November 17, 2010, Williams will have the
option to increase its ownership up to 50 percent, with the purchase price being
determined in accordance with the joint venture’s operating
agreement.  If Williams exercises its option to increase its ownership
to the full 50 percent, Williams would have the option to become
operator.  The pipeline project cost was approximately $575 million,
excluding AFUDC.





As part
of a long-term agreement, Williams dedicated its NGL production from two of its
natural gas processing plants in Wyoming to the Overland Pass
Pipeline.  We will provide downstream fractionation, storage and
transportation services to Williams.





The ONEOK Transactions - In
April 2006, we completed the acquisition of 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.  After this acquisition, ONEOK owned


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approximately
37.0 million of our common units, which, when combined with its general partner
interest, increased its total interest in us to approximately 45.7 percent at
the date of acquisition.  We used $1.05 billion drawn under a $1.1
billion, 364-day credit agreement, 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 66-2/3 percent 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.





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





Three
      Months EndedONEOK
      Energy Assets
                      
                      March
      31, 2006(Thousands
      of dollars)Revenue
                      
                      $
                      1,162,571Cost
      of sales and fuel
                      
                      
                      1,013,851Net
      margin
                      
                      
                      148,720Operating
      expensesOperations
      and maintenance
                      
                      
                      47,530Depreciation
      and amortization
                      
                      
                      19,277General
      taxes
                      
                      
                      4,407Total
      operating expenses
                      
                      
                      71,214Operating
      income
                      
                      
                      77,506Interest
      expense
                      
                      
                      21,281Other
      income, net
                      
                      
                      1,760Income
      before income taxes
                      
                      
                      57,985Income
      taxes
                      
                      
                      22,167Net
      income
                      
                      $
                      35,818Limited
      partners’ interest in net income:Net
      income
                      
                      $
                      35,818General
      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 Statement 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 the 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


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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 units
issued to ONEOK were the newly created Class B limited partner
units.  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.





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 66-2/3 percent interest in Guardian Pipeline not previously owned
by us for approximately $77 million, increasing our ownership interest to 100
percent.  We used borrowings from our credit facility to fund the
acquisition of the additional interest in Guardian
Pipeline.  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.              FAIR
VALUE MEASUREMENTS





As
discussed in Note A, we applied the provisions of Statement 157 as of January 1,
2008, to our recurring fair value measurements.





Determining Fair Value -
Statement 157 defines fair value as the price that would be received to sell an
asset or transfer a liability in an orderly transaction between market
participants at the measurement date.  We use the income approach to
determine the fair value of our derivative assets and liabilities and consider
the markets in which the transactions are executed.  While many of the
contracts in our portfolio are executed in liquid markets where price
transparency exists, some


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contracts
are executed in markets for which market prices may exist but the market may be
relatively inactive.  This results in limited price transparency that
requires management’s judgment and assumptions to estimate fair values. 
For certain transactions, we utilize modeling techniques using NYMEX-settled
pricing data and historical correlations of NGL product prices to crude
oil.  We validate our valuation inputs with third-party information
and settlement prices from other sources, where available.  In addition, as
prescribed by the income approach, we compute the fair value of our derivative
portfolio by discounting the projected future cash flows from our derivative
assets and liabilities to present value.  The interest rate yields
used to calculate the present-value discount factors are derived from LIBOR,
Eurodollar futures and Treasury swaps.  The projected cash flows are then
multiplied by the appropriate discount factors to determine the present value or
fair value of our derivative instruments.  Finally, we consider the credit
risk of our counterparties with whom our derivative assets and liabilities are
executed.  Although we use our best estimates to determine the fair value
of the derivative contracts we have executed, the ultimate market prices
realized could differ from our estimates, and the differences could be
significant.





Fair Value Hierarchy -
Statement 157 establishes the fair value hierarchy that prioritizes inputs to
valuation techniques based on observable and unobservable data and categorizes
the inputs into three levels, with the highest priority given to Level 1 and the
lowest priority given to Level 3.  The levels are described
below.


·
            Level
      1 - Unadjusted quoted prices in active markets for identical assets or
      liabilities.


·
            Level
      2 - Significant observable pricing inputs other than quoted prices
      included within Level 1 that are either directly or indirectly observable
      as of the reporting date.  Essentially, this represents inputs
      that are derived principally from or corroborated by observable market
      data.


·
            Level
      3 - Generally unobservable inputs, which are developed based on the best
      information available and may include our own internal
    data.





Determining
the appropriate classification of our fair value measurements within the fair
value hierarchy requires management’s judgment regarding the degree to which
market data is observable or corroborated by observable market
data.





Recurring Fair Value
Measurements - The following table sets forth our recurring fair value
measurements for the period indicated.




December
      31, 2008Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Total(Thousands
      of dollars)DerivativesAssets
                  
                  $
                  -
                  
                  
                  $
                  26,131
                  
                  
                  $
                  37,649
                  
                  
                  $
                  63,780





For
derivatives for which fair value is determined based on multiple inputs,
Statement 157 requires that the measurement for an individual derivative be
categorized within a single level based on the lowest level input that is
significant to the fair value measurement in its entirety.





When our
fair value measurements based on NYMEX-settled prices are associated with
exchange-traded instruments, we classify those derivatives as Level
1.  These measurements may include futures for natural gas and crude
oil that are valued based on unadjusted quoted prices in active
markets.  Our Level 2 fair value measurements are based on
NYMEX-settled prices that are utilized to determine the fair value of certain
non-exchange traded financial instruments, including natural gas and crude oil
swaps.  For our Level 3 inputs, we utilize modeling techniques using
NYMEX-settled pricing data and historical correlations of NGL product prices to
crude oil.




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The
following table sets forth a reconciliation of our Level 3 fair value
measurements for the period indicated.




Derivative
      Assets (Liabilities)(Thousands
      of dollars)Net
      liabilities at January 1, 2008
                                  $
                                  (16,400)Total
      realized/unrealized gains (losses):Included
      in earnings (a)
                                  
                                  980Included
      in other comprehensive income (loss)
                                  
                                  58,143Terminations
      prior to maturity
                                  
                                  (5,074)Transfers
      in and/or out of Level 3
                                  
                                  -Net
      assets at December 31, 2008
                                  $
                                  37,649Total
      gains (losses) for the period included in earnings attributable
      to
                                    the change in unrealized gains
      (losses) relating to assets and
                                    liabilities still held as of
      December 31, 2008 (a)
                                  $
                                  -(a)
      - Reported in revenues in our Consolidated Statements of
      Income.




Our Level
3 fair value measurements changed from a net liability position at January 1,
2008, to a net asset position at December 31, 2008, due to new hedges being put
in place during the period as well as changes in commodity
prices.  Realized/unrealized gains (losses) include the realization of
our fair value derivative contracts through maturity.  Terminations
prior to maturity represent swap contracts terminated prior to maturity
that will remain in accumulated other comprehensive income
(loss) until the underlying forecasted transaction occurs.





Fair Value of Debt- 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 $2.4 billion and $2.7 billion at December 31, 2008 and 2007,
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 our borrowings under
our amended and restated revolving credit agreement dated March 30, 2007
(Partnership Credit Agreement) approximates the carrying value since the
interest rates are periodically adjusted to reflect current market
conditions.





D.              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.  See Note A for discussion of our accounting policies for
derivatives and risk management.





Cash Flow Hedges - 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 our exposure to volatility in the price of natural gas, NGLs and
condensate.  At December 31, 2008, our Consolidated Balance Sheet
reflected an unrealized gain of $68.9 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 revenues in the period the ineffectiveness occurs.  Ineffectiveness
related to our cash flow hedges was not material in 2008 or
2007.  Ineffectiveness related to these cash flow hedges resulted in a
gain of approximately $4.5 million for 2006.  In the event that it
becomes probable that a forecasted transaction will not occur, we would
discontinue cash flow hedge treatment, which would affect
earnings.  There were no gains or losses during 2008, 2007 or 2006 due
to the discontinuance of cash flow hedge treatment.




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Fair Value Hedges - In 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.  Interest expense savings for 2008 from amortization of
terminated swaps was $3.7 million, and the remaining amortization of terminated
swaps will be recognized over the following periods.


(Millions
      of dollars)2009
                                    $
                                    
                                    
                                    3.72010
                                    $
                                    
                                    
                                    3.72011
                                    $
                                    
                                    
                                    0.9





At
December 31, 2008, none of the interest on our fixed-rate debt was swapped to
floating using interest-rate swaps.





E.              GOODWILL
AND INTANGIBLE ASSETS





Goodwill





Carrying Amount - The table
below shows goodwill recorded on our Consolidated Balance Sheet for the periods
indicated.





December
      31,2008
                                              
                                              2007(Thousands
      of dollars)Natural
      Gas Gathering and Processing
                                              
                                              $
                                              $90,037
                                              
                                              $
                                              90,037Natural
      Gas Pipelines
                                              
                                              
                                              131,115
                                              
                                              
                                              128,997Natural
      Gas Liquids Gathering and Fractionation
                                              
                                              
                                              175,566
                                              
                                              
                                              175,566Goodwill
                                              
                                              $
                                              $396,718
                                              
                                              $
                                              394,600





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, 2008 and 2007.





Impairment Test-We apply the provisions
of Statement 142 and perform our annual impairment test on July
1.  There were no impairment charges resulting from our July 1, 2008,
impairment test.  As a result of recent events in the financial
markets and current economic conditions, we performed a review and determined
that interim testing of goodwill as of December 31, 2008, was not
necessary.





Black Mesa - During 2006, we
reassessed our coal slurry pipeline operation and concluded that the likelihood
of Black Mesa Pipeline 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.




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Intangible
Assets





Our
intangible assets primarily relate to contracts acquired through acquisition,
which are being amortized over an aggregate weighted-average period of 40
years.  Amortization expense for intangible assets for both 2008 and
2007 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, 2008Gross
                      Intangible
      Assets
                    
                    
                    Accumulated
      Amortization
                    
                    
                    Net
                      Intangible
      Assets(Thousands
      of dollars)Natural
      Gas Liquids Gathering and Fractionation
                    
                    $
                    292,000
                    
                    
                    $
                    (25,549
                    )
                    
                    $
                    266,451Natural
      Gas Liquids Pipelines
                    
                    
                    14,650
                    
                    
                    
                    (1,283
                    )
                    
                    
                    13,367Intangible
      Assets
                    
                    $
                    306,650
                    
                    
                    $
                    (26,832
                    )
                    
                    $
                    279,818




December
      31, 2007Gross
                      Intangible
      Assets
                    
                    
                    Accumulated
      Amortization
                    
                    
                    Net
                      Intangible
      Assets(Thousands
      of dollars)Natural
      Gas Liquids Gathering and Fractionation
                    
                    $
                    292,000
                    
                    
                    $
                    (18,249
                    )
                    
                    $
                    273,751Natural
      Gas Liquids Pipelines
                    
                    
                    14,650
                    
                    
                    
                    (917
                    )
                    
                    
                    13,733Intangible
      Assets
                    
                    $
                    306,650
                    
                    
                    $
                    (19,166
                    )
                    
                    $
                    287,484





F.              OTHER
COMPREHENSIVE INCOME (LOSS)





The table
below shows other comprehensive income (loss) for the periods
indicated.




Years
      Ended December 31,2008
                                              
                                              2007(Thousands
      of dollars)Unrealized
      gains (losses) on derivatives
                                              $
                                              $68,159
                                              
                                              $
                                              (16,555)Less:  Realized
      losses recognized in net income
                                              
                                              (14,387)
                                              
                                              
                                              -Other
      comprehensive income (loss)
                                              $
                                              $82,546
                                              
                                              $
                                              (16,555)





The table
below shows the balance in accumulated other comprehensive income (loss) for the
periods indicated.




Unrealized
      Gains
                        (Losses)
      on Derivatives(Thousands
      of dollars)December
      31, 2006
                      $
                      (1,586)Other
      comprehensive income (loss)
                      
                      (16,555)December
      31, 2007
                      
                      (18,141)Other
      comprehensive income (loss)
                      
                      82,546December
      31, 2008
                      $
                      64,405





G.              PARTNERS’
EQUITY





ONEOK - ONEOK and its
affiliates own all of the Class B units, 5,900,000 common units and the entire 2
percent general partner interest in us, which together constituted a 47.7
percent ownership interest in us at December 31, 2008.





Equity Issuance - In March
2008, we completed a public offering of 2.5 million common units at $58.10 per
common unit, generating net proceeds of approximately $140.4 million after
deducting underwriting discounts but before offering expenses.  In
addition, we sold 5.4 million common units to ONEOK in a private placement,
generating proceeds of approximately $303.2 million.  In conjunction
with the public offering of common units and the private placement, ONEOK
Partners GP contributed $9.4 million in order to maintain its 2 percent general
partner interest in us.


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In April
2008, we sold an additional 128,873 common units at $58.10 per common unit to
the underwriters of the public offering upon the partial exercise of their
option to purchase additional common units to cover
over-allotments.  We received net proceeds of approximately $7.2
million from the sale of the common units after deducting underwriting discounts
but before offering expenses.  In conjunction with the partial
exercise by the underwriters, ONEOK Partners GP contributed $0.2 million in
order to maintain its 2 percent general partner interest in us.





We used a
portion of the proceeds from the sale of common units and the general partner
contributions to repay borrowings under our Partnership Credit
Agreement.





Cash Distributions- The
following summarizes our quarterly cash distribution activity for
2008:


·
            In
      January 2008, we declared a cash distribution of $1.025 per unit for the
      fourth quarter of 2007.  The distribution was paid on February
      14, 2008, to unitholders of record as of January 31,
  2008;


·
            In
      April 2008, we declared a cash distribution of $1.04 per unit for the
      first quarter of 2008.  The distribution was paid on May 15,
      2008, to unitholders of record as of April 30,
      2008;


·
            In
      July 2008, we declared a cash distribution of $1.06 per unit for the
      second quarter of 2008.  The distribution was paid on August 14,
      2008, to unitholders of record as of July 31, 2008;
  and


·
            In
      October 2008, we declared a cash distribution of $1.08 per unit for the
      third quarter of 2008. The distribution was paid on November 14, 2008, to
      unitholders of record as of October 31,
2008.





On
January 13, 2009, we declared a cash distribution of $1.08 per unit ($4.32 per
unit on an annualized basis) for the fourth quarter of 2008.  The
distribution was paid on February 13, 2009, to unitholders of record as of
January 30, 2009.





Partnership Agreement - 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 available cash within
45 days following the end of each quarter.  Available cash generally
consists of all cash receipts adjusted for cash disbursements and net changes to
cash reserves.  Available cash will generally be distributed 98
percent to limited partners and 2 percent to 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.  See Note N for additional information about
distributions allocated to the general partner.





H.              CREDIT
FACILITIES





In March
2007, we amended and restated our revolving 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 Partnership Credit Agreement to
increase the commitment amounts by $250 million to a total of $1.0
billion.





Under our
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 plus  minority interest in income of consolidated
subsidiaries, distributions received from investments and the equity
portion of AFUDC) of no more than 5 to 1.  If we consummate one or
more acquisitions in which the aggregate


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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 in our Partnership Credit Agreement, amounts outstanding
under such agreement may become immediately due and payable.  At
December 31, 2008, our ratio of indebtedness to adjusted EBITDA was 4.1 to 1,
and we were in compliance with all covenants under our Partnership Credit
Agreement.





The
average interest rate of borrowings under this agreement was 4.22 percent and
5.40 percent at December 31, 2008 and 2007, respectively.  We had $870
million and $100 million of borrowings outstanding and $130 million and $900
million available under our Partnership Credit Agreement at December 31, 2008
and 2007, respectively.





We have
an outstanding $25 million letter of credit issued by Royal Bank of Canada,
which is used for counterparty credit support.





We also
have 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
an agreement with Royal Bank of Canada, pursuant to which a $12 million letter
of credit was issued.  Both agreements are used to support various
permits required by the KDHE for our ongoing business in Kansas.





I.           LONG-TERM
DEBT





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




December
      31,
                                                          
                                                          
                                                          December
      31,2008
                                                          
                                                          
                                                          2007(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
                                                          
                                                          
                                                          
                                                          600,0002,475,000
                                                          
                                                          
                                                          
                                                          2,475,000Guardian
      PipelineAverage
      7.85% due 2022
                                                          
                                                          
                                                          121,711
                                                          
                                                          
                                                          
                                                          133,641Total
      long-term notes payable
                                                          
                                                          
                                                          2,596,711
                                                          
                                                          
                                                          
                                                          2,608,641Unamortized
      portion of terminated swaps
                                                          
                                                          
                                                          8,414
                                                          
                                                          
                                                          
                                                          12,155Unamortized
      debt premium
                                                          
                                                          
                                                          (3,685
                                                          )
                                                          
                                                          
                                                          (3,470
                                                          )Current
      maturities
                                                          
                                                          
                                                          (11,931
                                                          )
                                                          
                                                          
                                                          (11,930
                                                          )Long-term
      debt
                                                          
                                                          $
                                                          2,589,509
                                                          
                                                          
                                                          $
                                                          2,605,396





The
aggregate maturities of long-term debt outstanding for years 2009 through 2013
are shown below.




ONEOK
                                                
                                                GuardianPartners
                                                
                                                Pipeline
                                                
                                                Total(Millions
      of dollars)2009
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                11.9
                                                
                                                
                                                $
                                                11.92010
                                                
                                                $
                                                250.0
                                                
                                                
                                                $
                                                11.9
                                                
                                                
                                                $
                                                261.92011
                                                
                                                $
                                                225.0
                                                
                                                
                                                $
                                                11.9
                                                
                                                
                                                $
                                                236.92012
                                                
                                                $
                                                350.0
                                                
                                                
                                                $
                                                11.1
                                                
                                                
                                                $
                                                361.12013
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                7.7
                                                
                                                
                                                $
                                                7.7





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.


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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.





Debt Covenants - The indenture
governing the 2037 Notes 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.





Our $250
million and $225 million senior notes, 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 notes due
2012, 2016, 2036 and 2037 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.  At December
31, 2008, the Intermediate Partnership held partnership interests and the equity
in our subsidiaries, as well as a 50 percent interest in Northern Border
Pipeline.





The
Northern Border Pipeline partnership agreement provides that distributions to
Northern Border Pipeline’s partners are to be made on a pro rata basis according
to each partner’s percentage interest.  The Northern Border Pipeline
Management Committee determines the amount and timing of such
distributions.  Any changes to, or suspension of, the cash
distribution policy of Northern Border Pipeline requires the unanimous approval
of the Northern Border Pipeline Management Committee.  Cash
distributions are equal to 100 percent of distributable cash flow as determined
from Northern Border Pipeline’s financial statements based upon earnings before
interest, taxes, depreciation and amortization less interest expense and
maintenance capital expenditures.  Loans or other advances from
Northern Border Pipeline to its partners or affiliates are prohibited under its
credit agreement.  The Northern Border Pipeline Management Committee
has adopted a cash distribution policy related to financial ratio targets and
capital contributions.  The cash distribution policy defines 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.  See
Notes J and M for discussion of our investment in Northern Border
Pipeline.





Guardian Pipeline Senior Notes
- These notes were issued under a master shelf agreement with certain financial
institutions.  Principal payments are due quarterly through
2022.  Interest rates on the $121.7 million in notes outstanding at
December 31, 2008, range from 7.61 percent to 8.27 percent, with an average rate
of 7.85 percent.  Guardian Pipeline’s senior notes contain financial
covenants that require the maintenance of a ratio of (i) EBITDAR (net income
plus interest expense, income taxes, operating lease expense and depreciation
and amortization) to fixed charges (interest expense plus operating lease
expense) of not less than 1.5 to 1 and (ii) total indebtedness to EBITDAR of not
greater than 5.75 to 1.  Upon any breach of these covenants, all
amounts outstanding under the master shelf agreement may become due and payable
immediately.  At December 31, 2008, Guardian Pipeline’s
EBITDAR-to-fixed-charges ratio was 4.95 to 1,the ratio of indebtedness to
EBITDAR was 3.34 to 1, and Guardian Pipeline was in compliance with its
financial covenants.





Other





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.




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J.              COMMITMENTS
AND CONTINGENCIES





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





(Millions
      of dollars)2009
                                                              
                                                              $
                                                              18.42010
                                                              
                                                              $
                                                              16.02011
                                                              
                                                              $
                                                              15.52012
                                                              
                                                              $
                                                              8.82013
                                                              
                                                              $
                                                              2.1





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 November 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 $11.7 million,
$11.9 million and $12.0 million for 2008, 2007 and 2006, respectively, related
to these agreements.  At December 31, 2008, the estimated aggregate
amounts of such required future payments were $11.1 million for 2009 and $3.7
million for 2010.





Investment in Northern Border
Pipeline - Northern Border Pipeline anticipates an equity contribution of
approximately $85 million that will be required of its partners in 2009, of
which our share will be approximately $43 million for our 50 percent equity
interest.





Environmental Liabilities-We are
subject to multiple environmental, historical and wildlife preservation laws and
regulations affecting many aspects of our present and future
operations.  Regulated activities include those involving air
emissions, stormwater, wastewater discharges, handling and disposal of solid and
hazardous wastes, hazardous materials transportation, and pipeline and facility
construction.  These laws and regulations require us to obtain and
comply with a wide variety of environmental clearances, registrations, licenses,
permits and other approvals.  Failure to comply with these laws,
regulations, permits and licenses may expose us to fines, penalties and/or
interruptions in our operations that could be material to our results of
operations.  If a leak or spill of hazardous substances or petroleum
products 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, mitigation and remediation to date
have not been significant in relation to our results of operations, and there
were no material effects upon earnings during 2008, 2007 or 2006 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.





FERC Matter- As a result of a
transaction that was brought to the attention of one of our affiliates by a
third party, we conducted an internal review of transactions that may have
violated FERC natural gas capacity release rules or related rules and determined
that there were transactions that should be disclosed to the FERC.  We
notified the FERC of this review and filed a report with the FERC regarding
these transactions in March 2008.  We cooperated fully with the FERC
in its investigation of this matter and have taken steps to better ensure that
current and future transactions comply with applicable FERC regulations by
implementing a compliance plan dealing with capacity release.  We,
along with ONEOK, entered into a global settlement with the FERC to resolve this
matter and other FERC enforcement matters, which was approved by the FERC on
January 15, 2009.  The global settlement provides for a total civil
penalty of $4.5 million and approximately $2.2 million in disgorgement of
profits and interest.  We are responsible for $1.7 million in civil
penalties, which is recorded as a liability on our Consolidated Balance Sheet as
of December 31, 2008, and the disgorgement of profits and interests are the
responsibility of ONEOK.  We made the required payments in January
2009.


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K.              INCOME
TAXES





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




Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006(Thousands
      of dollars)Taxes
      currently payable:Federal
                    
                    $
                    80
                    
                    
                    $
                    72
                    
                    
                    $
                    -State
                    
                    
                    7,240
                    
                    
                    
                    4,203
                    
                    
                    
                    -Total
      taxes currently payable
                    
                    
                    7,320
                    
                    
                    
                    4,275
                    
                    
                    
                    -Deferred
      taxes:Federal
                    
                    
                    4,785
                    
                    
                    
                    3,994
                    
                    
                    
                    2,163State
                    
                    
                    230
                    
                    
                    
                    573
                    
                    
                    
                    3,339Total
      deferred taxes
                    
                    
                    5,015
                    
                    
                    
                    4,567
                    
                    
                    
                    5,502Taxes
      retained by ONEOK
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    22,167Total
      tax provision
                    
                    $
                    12,335
                    
                    
                    $
                    8,842
                    
                    
                    $
                    27,669





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





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




Years
      Ended December 31,2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006(Thousands
      of dollars)Pretax
      income
                                  $
                                  637,951
                                  
                                  $
                                  416,589
                                  
                                  $
                                  420,849Federal
      statutory income tax rate
                                  
                                  35.0%
                                  
                                  
                                  35.0%
                                  
                                  
                                  35.0%Provision
      for federal income taxes
                                  
                                  223,283
                                  
                                  
                                  145,806
                                  
                                  
                                  147,297Partnership
      earnings not subject to tax
                                  
                                  (216,332)
                                  
                                  
                                  (141,884)
                                  
                                  
                                  (144,928)State
      income taxes
                                  
                                  7,470
                                  
                                  
                                  4,772
                                  
                                  
                                  2,990Other,
      net
                                  
                                  (2,086)
                                  
                                  
                                  148
                                  
                                  
                                  143Income
      tax expense
                                  $
                                  12,335
                                  
                                  $
                                  8,842
                                  
                                  $
                                  5,502





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 31,2008
                      
                      
                      2007(Thousands
      of dollars)Deferred
      tax assets:Net
      operating losses
                      
                      $
                      4,226
                      
                      
                      $
                      4,715Other
                      
                      
                      44
                      
                      
                      
                      1,596Total
      deferred tax assets
                      
                      
                      4,270
                      
                      
                      
                      6,311Deferred
      tax liabilities:Excess
      of tax over book depreciation and depletion
                      
                      
                      9,660
                      
                      
                      
                      7,934Employee
      benefits
                      
                      
                      790
                      
                      
                      
                      -Regulatory
      assets
                      
                      
                      3,733
                      
                      
                      
                      2,544Other
                      
                      
                      823
                      
                      
                      
                      77Total
      deferred tax liabilities
                      
                      
                      15,006
                      
                      
                      
                      10,555Net
      deferred tax assets (liabilities)
                      
                      $
                      (10,736
                      )
                      
                      $
                      (4,244
                      )





At
December 31, 2008, we had approximately $4.2 million of tax benefits available
related to net operating loss carryforwards, which will expire between the years
2022 and 2027.  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.


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We had
income taxes payable of approximately $7.2 million and $3.1 million at December
31, 2008 and 2007, respectively.





L.              SEGMENTS





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


·
            our
      Natural Gas Gathering and Processing segment primarily gathers and
      processes unprocessed 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 owns and operates
      FERC-regulated interstate natural gas liquids gathering and distribution
      pipelines.





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 subsidiaries of
ONEOK that utilize our transportation and storage services.  Overhead
costs relating to a reportable segment have been allocated for the purpose of
calculating operating income.





Customers - The primary
customers for our Natural Gas Gathering and Processing segment are 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 2008,
2007 and 2006, we had no single external customer from which we received 10
percent or more of our consolidated revenues.





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
      Ended December 31, 2008
                  Natural
      Gas Gathering and Processing
                  
                  
                  Natural
      Gas Pipelines (a)
                  
                  
                  Natural
      Gas Liquids
                    Gathering
      and Fractionation
                  
                  
                  Natural
      Gas Liquids
                    Pipelines
      (b)
                  
                  
                  Other
      and Eliminations
                  
                  
                  Total(Thousands
      of dollars)Sales
      to unaffiliated customers
                  
                  $
                  447,293
                  
                  
                  $
                  223,223
                  
                  
                  $
                  6,241,296
                  
                  
                  $
                  63,460
                  
                  
                  $
                  48
                  
                  
                  $
                  6,975,320Sales
      to affiliated customers
                  
                  
                  627,774
                  
                  
                  
                  117,112
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  744,886Intersegment
      revenues
                  
                  
                  681,172
                  
                  
                  
                  1,788
                  
                  
                  
                  28,439
                  
                  
                  
                  93,631
                  
                  
                  
                  (805,030
                  )
                  
                  
                  -Total
      revenues
                  
                  $
                  1,756,239
                  
                  
                  $
                  342,123
                  
                  
                  $
                  6,269,735
                  
                  
                  $
                  157,091
                  
                  
                  $
                  (804,982
                  )
                  
                  $
                  7,720,206Net
      margin
                  
                  $
                  435,223
                  
                  
                  $
                  257,362
                  
                  
                  $
                  317,704
                  
                  
                  $
                  132,697
                  
                  
                  $
                  (2,327
                  )
                  
                  $
                  1,140,659Operating
      costs
                  
                  
                  138,196
                  
                  
                  
                  89,878
                  
                  
                  
                  89,839
                  
                  
                  
                  55,060
                  
                  
                  
                  (1,176
                  )
                  
                  
                  371,797Depreciation
      and amortization
                  
                  
                  49,883
                  
                  
                  
                  34,279
                  
                  
                  
                  23,485
                  
                  
                  
                  17,097
                  
                  
                  
                  21
                  
                  
                  
                  124,765Gain
      (loss) on sale of assets
                  
                  
                  4
                  
                  
                  
                  (17
                  )
                  
                  
                  33
                  
                  
                  
                  10
                  
                  
                  
                  683
                  
                  
                  
                  713Operating
      income
                  
                  $
                  247,148
                  
                  
                  $
                  133,188
                  
                  
                  $
                  204,413
                  
                  
                  $
                  60,550
                  
                  
                  $
                  (489
                  )
                  
                  $
                  644,810Equity
      earnings from investments
                  
                  $
                  32,825
                  
                  
                  $
                  66,653
                  
                  
                  $
                  -
                  
                  
                  $
                  1,954
                  
                  
                  $
                  -
                  
                  
                  $
                  101,432Investments
      in unconsolidated
                    affiliates
                  
                  $
                  324,709
                  
                  
                  $
                  400,986
                  
                  
                  $
                  -
                  
                  
                  $
                  29,797
                  
                  
                  $
                  -
                  
                  
                  $
                  755,492Minority
      interests in consolidated
                    subsidiaries
                  
                  $
                  -
                  
                  
                  $
                  5,797
                  
                  
                  $
                  -
                  
                  
                  $
                  129
                  
                  
                  $
                  15
                  
                  
                  $
                  5,941Total
      assets
                  
                  $
                  1,613,903
                  
                  
                  $
                  1,477,301
                  
                  
                  $
                  1,717,550
                  
                  
                  $
                  1,903,568
                  
                  
                  $
                  541,950
                  
                  
                  $
                  7,254,272Capital
      expenditures
                  
                  $
                  146,249
                  
                  
                  $
                  267,029
                  
                  
                  $
                  169,510
                  
                  
                  $
                  670,926
                  
                  
                  $
                  139
                  
                  
                  $
                  1,253,853(a)
      - Our Natural Gas Pipelines segment has regulated and non-regulated
      operations. Our Natural Gas Pipelines segment’s regulated operations
      had revenues of $282.2 million, net margin of $201.4 million and operating
      income of $98.2 million.(b)
      - All of our Natural Gas Liquids Pipelines segment’s operations are
      regulated.




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Year
      Ended December 31, 2007
                  
                  Natural
      Gas Gathering and Processing
                  
                  
                  Natural
      Gas Pipelines (a)
                  
                  
                  Natural
      Gas Liquids
                    Gathering
      and Fractionation
                  
                  
                  Natural
      Gas Liquids
                    Pipelines
      (b)
                  
                  
                  Other
      and
                    Eliminations
                  
                  
                  Total(Thousands
      of dollars)Sales
      to unaffiliated customers
                  
                  $
                  433,139
                  
                  
                  $
                  194,170
                  
                  
                  $
                  4,562,178
                  
                  
                  $
                  15,280
                  
                  
                  $
                  27
                  
                  
                  $
                  5,204,794Sales
      to affiliated customers
                  
                  
                  519,755
                  
                  
                  
                  107,009
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  626,764Intersegment
      revenues
                  
                  
                  505,756
                  
                  
                  
                  785
                  
                  
                  
                  25,115
                  
                  
                  
                  76,555
                  
                  
                  
                  (608,211
                  )
                  
                  
                  -Total
      revenues
                  
                  $
                  1,458,650
                  
                  
                  $
                  301,964
                  
                  
                  $
                  4,587,293
                  
                  
                  $
                  91,835
                  
                  
                  $
                  (608,184
                  )
                  
                  $
                  5,831,558Net
      margin
                  
                  $
                  366,511
                  
                  
                  $
                  241,097
                  
                  
                  $
                  205,764
                  
                  
                  $
                  81,472
                  
                  
                  $
                  1,049
                  
                  
                  $
                  895,893Operating
      costs
                  
                  
                  135,422
                  
                  
                  
                  96,584
                  
                  
                  
                  70,693
                  
                  
                  
                  28,957
                  
                  
                  
                  5,700
                  
                  
                  
                  337,356Depreciation
      and amortization
                  
                  
                  45,099
                  
                  
                  
                  32,380
                  
                  
                  
                  23,134
                  
                  
                  
                  13,062
                  
                  
                  
                  29
                  
                  
                  
                  113,704Gain
      (loss) on sale of assets
                  
                  
                  1,825
                  
                  
                  
                  79
                  
                  
                  
                  39
                  
                  
                  
                  7
                  
                  
                  
                  -
                  
                  
                  
                  1,950Operating
      income
                  
                  $
                  187,815
                  
                  
                  $
                  112,212
                  
                  
                  $
                  111,976
                  
                  
                  $
                  39,460
                  
                  
                  $
                  (4,680
                  )
                  
                  $
                  446,783Equity
      earnings from investments
                  
                  $
                  26,399
                  
                  
                  $
                  62,487
                  
                  
                  $
                  -
                  
                  
                  $
                  1,022
                  
                  
                  $
                  -
                  
                  
                  $
                  89,908Investments
      in unconsolidated
                    affiliates
                  
                  $
                  298,701
                  
                  
                  $
                  426,992
                  
                  
                  $
                  -
                  
                  
                  $
                  30,567
                  
                  
                  $
                  -
                  
                  
                  $
                  756,260Minority
      interests in consolidated
                    subsidiaries
                  
                  $
                  -
                  
                  
                  $
                  5,758
                  
                  
                  $
                  -
                  
                  
                  $
                  29
                  
                  
                  $
                  15
                  
                  
                  $
                  5,802Total
      assets
                  
                  $
                  1,521,514
                  
                  
                  $
                  1,241,507
                  
                  
                  $
                  1,880,602
                  
                  
                  $
                  1,185,513
                  
                  
                  $
                  282,929
                  
                  
                  $
                  6,112,065Capital
      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, net margin of $192.2 million and operating
      income of $82.9 million.(b)
      - All of our Natural Gas Liquids Pipelines segment’s operations are
      regulated.


Year
      Ended December 31, 2006
                    
                    Natural
      Gas Gathering and Processing
                    
                    
                    Natural
      Gas Pipelines (a)
                    
                    
                    Natural
      Gas Liquids
                      Gathering
      and Fractionation
                    
                    
                    Natural
      Gas Liquids
                      Pipelines
      (b)
                    
                    
                    Other
      and
                      Eliminations
                    
                    
                    Total(Thousands
      of dollars)Sales
      to unaffiliated customers
                    
                    $
                    478,848
                    
                    
                    $
                    195,063
                    
                    
                    $
                    3,467,048
                    
                    
                    $
                    -
                    
                    
                    $
                    1,587
                    
                    
                    $
                    4,142,546Sales
      to affiliated customers
                    
                    
                    476,361
                    
                    
                    
                    121,088
                    
                    
                    
                    (1,747)
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    595,702Intersegment
      revenues
                    
                    
                    520,881
                    
                    
                    
                    857
                    
                    
                    
                    27,675
                    
                    
                    
                    66,496
                    
                    
                    
                    (615,909
                    )
                    
                    
                    -Total
      revenues
                    
                    $
                    1,476,090
                    
                    
                    $
                    317,008
                    
                    
                    $
                    3,492,976
                    
                    
                    $
                    66,496
                    
                    
                    $
                    (614,322
                    )
                    
                    $
                    4,738,248Net
      margin
                    
                    $
                    370,761
                    
                    
                    $
                    246,797
                    
                    
                    $
                    166,981
                    
                    
                    $
                    60,447
                    
                    
                    $
                    (1,438)
                    
                    
                    $
                    843,548Operating
      costs
                    
                    
                    147,487
                    
                    
                    
                    91,516
                    
                    
                    
                    57,511
                    
                    
                    
                    19,333
                    
                    
                    
                    9,927
                    
                    
                    
                    325,774Depreciation
      and amortization
                    
                    
                    43,032
                    
                    
                    
                    32,841
                    
                    
                    
                    20,738
                    
                    
                    
                    12,035
                    
                    
                    
                    13,399
                    
                    
                    
                    122,045Gain
      (loss) on sale of assets
                    
                    
                    373
                    
                    
                    
                    114,890
                    
                    
                    
                    47
                    
                    
                    
                    7
                    
                    
                    
                    166
                    
                    
                    
                    115,483Operating
      income
                    
                    $
                    180,615
                    
                    
                    $
                    237,330
                    
                    
                    $
                    88,779
                    
                    
                    $
                    29,086
                    
                    
                    $
                    (24,598
                    )
                    
                    $
                    511,212Equity
      earnings from investments
                    
                    $
                    22,616
                    
                    
                    $
                    72,835
                    
                    
                    $
                    -
                    
                    
                    $
                    432
                    
                    
                    $
                    -
                    
                    
                    $
                    95,883Investments
      in unconsolidated
                      affiliates
                    
                    $
                    294,308
                    
                    
                    $
                    445,339
                    
                    
                    $
                    -
                    
                    
                    $
                    9,232
                    
                    
                    $
                    -
                    
                    
                    $
                    748,879Minority
      interests in consolidated
                      subsidiaries
                    
                    $
                    -
                    
                    
                    $
                    5,476
                    
                    
                    $
                    -
                    
                    
                    $
                    115
                    
                    
                    $
                    15
                    
                    
                    $
                    5,606Total
      assets
                    
                    $
                    1,447,238
                    
                    
                    $
                    1,075,811
                    
                    
                    $
                    1,458,818
                    
                    
                    $
                    514,164
                    
                    
                    $
                    425,686
                    
                    
                    $
                    4,921,717Capital
      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, net margin of $201.4 million and operating
      income of $211.0 million, including $113.9 million from a gain on sale of
      assets.(b)
      - All of our Natural Gas Liquids Pipelines segment’s operations are
      regulated.




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M.              UNCONSOLIDATED
AFFILIATES





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





Net Ownership
                                              
                                              December
      31,
                                              
                                              
                                              December
      31,Interest
                                              
                                              2008
                                              
                                              
                                              2007(Thousands
      of dollars)Northern
      Border Pipeline
                                              
                                              
                                              50%
                                              
                                              
                                              $
                                              392,601
                                              
                                              
                                              
                                              $
                                              418,982Bighorn
      Gas Gathering
                                              
                                              
                                              49%
                                              
                                              
                                              
                                              97,289
                                              
                                              
                                              
                                              
                                              97,716Fort
      Union Gas Gathering
                                              
                                              
                                              37%
                                              
                                              
                                              
                                              108,642
                                              
                                              
                                              
                                              
                                              85,197Lost
      Creek Gathering Company (a)
                                              
                                              
                                              35%
                                              
                                              
                                              
                                              77,773
                                              
                                              
                                              
                                              
                                              75,612Other
                                              
                                              Various
                                              
                                              
                                              
                                              79,187
                                              
                                              
                                              
                                              
                                              78,753Investments
      in unconsolidated affiliates
                                              
                                              
                                              
                                              
                                              
                                              $
                                              755,492
                                              
                                              (b)
                                              
                                              $
                                              756,260
                                              
                                              (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 our 35 percent ownership
      interest.(b)
      - Equity method goodwill (Note E) was $185.6 million at December 31, 2008
      and
2007.




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





Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006(Thousands
      of dollars)Northern
      Border Pipeline (a)
                    
                    $
                    65,912
                    
                    
                    $
                    62,008
                    
                    
                    $
                    72,393Bighorn
      Gas Gathering
                    
                    
                    8,195
                    
                    
                    
                    7,416
                    
                    
                    
                    8,223Fort
      Union Gas Gathering
                    
                    
                    14,172
                    
                    
                    
                    9,681
                    
                    
                    
                    9,030Lost
      Creek Gathering Company
                    
                    
                    5,365
                    
                    
                    
                    4,790
                    
                    
                    
                    5,363Other
                    
                    
                    7,788
                    
                    
                    
                    6,013
                    
                    
                    
                    874Equity
      earnings from investments
                    
                    $
                    101,432
                    
                    
                    $
                    89,908
                    
                    
                    $
                    95,883(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.




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





December
      31,2008
                  
                  
                  2007(Thousands
      of dollars)Balance
      SheetCurrent
      assets
                  
                  $
                  106,833
                  
                  
                  $
                  102,805Property,
      plant and equipment, net
                  
                  $
                  1,777,350
                  
                  
                  $
                  1,724,330Other
      noncurrent assets
                  
                  $
                  27,547
                  
                  
                  $
                  25,882Current
      liabilities
                  
                  $
                  279,996
                  
                  
                  $
                  79,593Long-term
      debt
                  
                  $
                  543,894
                  
                  
                  $
                  717,301Other
      noncurrent liabilities
                  
                  $
                  14,360
                  
                  
                  $
                  10,278Accumulated
      other comprehensive income (loss)
                  
                  $
                  (5,708
                  )
                  
                  $
                  (2,441
                  )Owners’
      equity
                  
                  $
                  1,079,188
                  
                  
                  $
                  1,048,286




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Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006(Thousands
      of dollars)Income
      StatementOperating
      revenue
                    
                    $
                    415,552
                    
                    
                    $
                    404,399
                    
                    
                    $
                    386,448Operating
      expenses
                    
                    $
                    179,380
                    
                    
                    $
                    172,997
                    
                    
                    $
                    159,452Net
      income
                    
                    $
                    209,915
                    
                    
                    $
                    184,434
                    
                    
                    $
                    183,732Distributions
      paid to us
                    
                    $
                    118,010
                    
                    
                    $
                    103,785
                    
                    
                    $
                    123,427





N.              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 common
units.  The general partner owns the entire 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: (i) an amount based upon the 2 percent general
partner interest in net income and (ii) 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 $76.0 million, $50.6 million and $31.6 million for
2008, 2007 and 2006, respectively.  Distributions paid to our general
partner and shown on our Consolidated Statements of Changes in Partners’ Equity
and Comprehensive Income of $78.9 million in 2008, $54.7 million in 2007, and
$28.4 million in 2006, included incentive distributions of $69.9 million, $47.1
million and $23.1 million in 2008, 2007 and 2006, 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.





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.





O.              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 that
utilize both transportation and storage services.  Additionally, our
Natural Gas Gathering and Processing segment and Natural Gas Liquids Gathering
and Fractionation segment purchase a portion of the natural gas used in their
operations from ONEOK and its subsidiaries.





As part
of the ONEOK Transactions, we have 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 provides to us
similar services that it provides to its 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.  ONEOK
Partners GP has no employees and utilizes the services of ONEOK and ONEOK
Services Company to fulfill its responsibilities.


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ONEOK and
its affiliates provide a variety of services to us under the Services Agreement,
including cash management and financial 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, earnings before interest and taxes and payroll
expense.  All costs directly charged or allocated to us are included
in our Consolidated Statements of Income.





An
affiliate of ONEOK enters into all commodity derivative contracts at the
direction of and on behalf of our Natural Gas Gathering and Processing
segment.  We have an indemnification agreement with ONEOK Energy
Services Company, L.P. (OES) that indemnifies and holds OES harmless from any
liability OES may incur solely as a result of entering into financial hedges on
our behalf.  See Note D 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 31,2008
                    
                    
                    2007
                    
                    
                    2006(Thousands
      of dollars)Revenues
                    
                    $
                    744,886
                    
                    
                    $
                    626,764
                    
                    
                    $
                    595,702ExpensesCost
      of sales and fuel
                    
                    $
                    107,983
                    
                    
                    $
                    89,792
                    
                    
                    $
                    177,367Administrative
      and general expenses
                    
                    
                    191,798
                    
                    
                    
                    171,741
                    
                    
                    
                    175,270Interest
      expense
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    21,372Total
      expenses
                    
                    $
                    299,781
                    
                    
                    $
                    261,533
                    
                    
                    $
                    374,009





In
addition, concurrent with our sale of common units to the public, we sold 5.4
million common units to ONEOK in March 2008 in a private placement, generating
proceeds of approximately $303.2 million.  ONEOK Partners GP also made
additional general partner contributions to us in March and April
2008.  See Note G for additional information.





P.              QUARTERLY
FINANCIAL DATA (UNAUDITED)




First
                  
                  
                  Second
                  
                  
                  Third
                  
                  
                  FourthYear
      Ended December 31, 2008
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter(Thousands
      of dollars, except per unit amounts)Revenues
                  
                  $
                  2,059,035
                  
                  
                  $
                  2,143,892
                  
                  
                  $
                  2,241,107
                  
                  
                  $
                  1,276,172Net
      margin
                  
                  $
                  268,525
                  
                  
                  $
                  280,933
                  
                  
                  $
                  325,400
                  
                  
                  $
                  265,801Operating
      income
                  
                  $
                  150,532
                  
                  
                  $
                  163,739
                  
                  
                  $
                  197,526
                  
                  
                  $
                  133,013Net
      income
                  
                  $
                  145,018
                  
                  
                  $
                  154,521
                  
                  
                  $
                  203,872
                  
                  
                  $
                  122,205Limited
      partners’ per unit net income
                  
                  $
                  1.48
                  
                  
                  $
                  1.46
                  
                  
                  $
                  1.97
                  
                  
                  $
                  1.09




First
                  
                  
                  Second
                  
                  
                  Third
                  
                  
                  FourthYear
      Ended December 31, 2007
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter(Thousands
      of dollars, except per unit amounts)Revenues
                  
                  $
                  1,168,674
                  
                  
                  $
                  1,375,314
                  
                  
                  $
                  1,410,257
                  
                  
                  $
                  1,877,313Net
      margin
                  
                  $
                  205,370
                  
                  
                  $
                  217,570
                  
                  
                  $
                  213,884
                  
                  
                  $
                  259,069Operating
      income
                  
                  $
                  104,376
                  
                  
                  $
                  107,558
                  
                  
                  $
                  105,116
                  
                  
                  $
                  129,733Net
      income
                  
                  $
                  95,756
                  
                  
                  $
                  94,619
                  
                  
                  $
                  95,916
                  
                  
                  $
                  121,456Limited
      partners’ per unit net income
                  
                  $
                  1.00
                  
                  
                  $
                  0.97
                  
                  
                  $
                  0.98
                  
                  
                  $
                  1.27





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





None.




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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, 2008.





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,
2008.





Our
internal control over financial reporting as of December 31, 2008, has been
audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report that is included herein (Item
8).





Changes
in Internal Controls Over Financial Reporting





We have
made 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 quarter ended
December 31, 2008, 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
qualifications and independence and our compliance with legal and regulatory
requirements.  The


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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, in making any such
determination, the Audit Committee has the authority 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 which is available on and
may be printed from our Web site at www.oneokpartners.com and is also available
from the corporate secretary of our general partner.





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.





Directors
and Executive Officers





The
following table sets forth the members of our 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 and
affiliates.





Name
                Age
                PositionJohn
      W. Gibson
                56
                Chairman
      of the Board and Chief Executive OfficerJames
      C. Kneale
                57
                President
      and Chief Operating Officer,Member,
      Board of DirectorsCurtis
      L. Dinan
                41
                Executive
      Vice President, Chief Financial Officer and Treasurer,Member,
      Board of DirectorsJohn
      R. Barker
                61
                Executive
      Vice President, General Counsel and SecretaryCaron
      A. Lawhorn
                47
                Senior
      Vice President and Chief Accounting OfficerGary
      N. Petersen
                57
                Member,
      Board of Directors and Audit CommitteeGerald
      B. Smith
                58
                Member,
      Board of Directors and Chairman, AuditCommitteeGil
      J. Van Lunsen
                66
                Member,
      Board of Directors and Audit Committee


John W.
Gibson became our 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 our president and chief operating officer effective May 15,
2008.  He was elected to our Board of Directors on October 1,
2006.  He has served as president and chief operating officer of ONEOK
since 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 executive vice president, chief financial officer and treasurer
effective May 15, 2008.  Mr. Dinan served as senior vice president,
chief financial officer and treasurer from January 1, 2007, to May 15,
2008.  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.


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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 GableGotwals, a law firm located in Tulsa, Oklahoma, which provides legal
services to us and to 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.  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.





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, and 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 founder,
chairman and chief executive officer of Smith, Graham & Company Investment
Advisors, a global investment management firm.  He is a member of the board
of directors of the Charles Schwab Family of Funds where he serves as chairman
of the investment oversight committee.  He also serves as lead
independent director and deputy chairman of Cooper Industries.  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, 2008, 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 $15,000 and each other member of the
Audit Committee received an additional cash fee of $10,000.  During
2008, the Chair of the Audit Committee received an additional $45,000 and the
other two members of the Audit Committee each received an additional $30,000 for
their services in determining the fairness of the terms and conditions of the
Partnership’s sale, in a private placement, of additional common units to ONEOK
in March 2008.  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.




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The
following table sets forth the compensation paid to our non-management directors
in 2008.





2008
DIRECTOR COMPENSATION





Fees
                  Earned
      or
                  Paid
      in
                  Cash
                
                
                Stock
                  Awards
                
                
                Option
                  Awards
                
                
                Non
      Equity
                  Incentive
      Plan
                  Compensation
                
                
                Change
      in
                  Pension
      Value
                  and
                  Nonqualified
                  Deferred
                  Compensation
                  Earnings
                
                
                All
      Other
                  Compensation
                
                
                TotalName
                
                ($)
                
                
                ($)
                
                
                ($)
                
                
                ($)
                
                
                ($)
                
                
                ($)
                
                
                ($)Gary
      N. Petersen
                
                
                110,000
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                110,000Gerald
      B. Smith
                
                
                130,000
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                130,000Gil
      J. Van Lunsen
                
                
                110,000
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                110,000





Compensation
Committee Interlocks and Insider Participation





We do not
have a compensation committee.  During 2008, the compensation of our
named executive officers was determined by ONEOK’s Executive Compensation
Committee, which consists of independent members of the ONEOK Board of
Directors.  No member of ONEOK’s Executive Compensation Committee is,
or was formerly, an officer, director or employee of ONEOK Partners or any if
its subsidiaries.





Governance
Matters





Audit Committee Independence -
Our Board of Directors has 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 2009, our Board of
Directors affirmatively determined that Messrs. Petersen, Smith, and 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 2009, our Board of Directors
determined that Messrs. Petersen, Smith, and 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. Van Lunsen serves on the audit committee of one other public
company.  The Board of Directors has determined that Mr. Van Lunsen’s
service on this other audit committee does not impair his 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
2008 fiscal year, or written representations from certain reporting persons that
no Form 5s were required for those persons, we believe that during 2008 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


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Directors of our general partner
recognizes that effective governance is an on-going process, and the Board of
Directors will review our Governance Guidelines periodically as deemed
necessary.




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 Web site 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.





Web Access- We provide access
through our Web site at www.oneokpartners.comto current information
relating to our governance, including our Audit Committee Charter, our Code of
Business Conduct, our Governance Guidelines and other matters impacting our
governance principles.  You may copy each of these documents from our
Web site.  You may also contact the office of the secretary of ONEOK
Partners GP for printed copies of these documents free of
charge.  However, our Web site and any contents thereof are not
incorporated by reference into this document.





Communicationswith 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 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 Person 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 2009 Proxy Statement as filed with the SEC (ONEOK 2009 Proxy
Statement), a copy of which will be provided on, and may be copied from, ONEOK’s
Web site 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 2008
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 2008




Name and
                  Principal
      Position
                Year
                
                Salary
                  ($)
                
                
                Stock
                  Awards
                  ($)(1)
                
                
                Option
                  Awards
                  ($)(2)
                
                
                Non-Equity
      Incentive Plan Compensation
                  ($)(3)
                
                
                Change
      in Pension
                  Value
      and
                  Nonqualified
                  Deferred
                  Compensation
                  Earnings
                  ($)(4)
                
                
                All
      Other Compensation
                  ($)(5)
                
                
                Total
                  ($)John
      W. Gibson
                2008
                
                $
                442,365
                
                
                $
                1,475,021
                
                
                $
                -
                
                
                $
                457,379
                
                
                $
                1,085,848
                
                
                $
                63,181
                
                
                $
                3,523,794Chief
      Executive Officer
                2007
                
                $
                295,926
                
                
                $
                930,262
                
                
                $
                -
                
                
                $
                536,963
                
                
                $
                505,584
                
                
                $
                67,930
                
                
                $
                2,336,6652006
                
                $
                326,250
                
                
                $
                794,237
                
                
                $
                2,210
                
                
                $
                491,250
                
                
                $
                483,617
                
                
                $
                43,448
                
                
                $
                2,141,012James
      C. Kneale
                2008
                
                $
                321,720
                
                
                $
                1,151,085
                
                
                $
                -
                
                
                $
                294,910
                
                
                $
                598,479
                
                
                $
                45,531
                
                
                $
                2,411,725President
      and Chief
                2007
                
                $
                248,196
                
                
                $
                849,464
                
                
                $
                64,309
                
                
                $
                389,000
                
                
                $
                420,392
                
                
                $
                33,201
                
                
                $
                2,004,562Operating
      Officer
                2006
                
                $
                158,014
                
                
                $
                441,904
                
                
                $
                173,629
                
                
                $
                227,032
                
                
                $
                261,635
                
                
                $
                21,875
                
                
                $
                1,284,089Curtis
      L. Dinan
                2008
                
                $
                214,480
                
                
                $
                255,391
                
                
                $
                -
                
                
                $
                147,455
                
                
                $
                44,230
                
                
                $
                25,094
                
                
                $
                686,650Executive
      Vice President,
                2007
                
                $
                143,190
                
                
                $
                122,707
                
                
                $
                -
                
                
                $
                181,374
                
                
                $
                20,826
                
                
                $
                13,667
                
                
                $
                481,764Chief
      Financial Officer
                2006
                
                $
                82,472
                
                
                $
                108,166
                
                
                $
                -
                
                
                $
                59,165
                
                
                $
                11,340
                
                
                $
                8,475
                
                
                $
                269,618and
      TreasurerPierce
      H. Norton II
                2008
                
                $
                249,687
                
                
                $
                209,706
                
                
                $
                -
                
                
                $
                172,119
                
                
                $
                37,002
                
                
                $
                28,860
                
                
                $
                697,374Executive
      Vice President -
                2007
                
                $
                261,354
                
                
                $
                199,306
                
                
                $
                -
                
                
                $
                320,000
                
                
                $
                39,437
                
                
                $
                14,233
                
                
                $
                834,330Natural
      Gas
                2006
                
                $
                225,000
                
                
                $
                165,200
                
                
                $
                -
                
                
                $
                215,000
                
                
                $
                35,725
                
                
                $
                13,683
                
                
                $
                654,608Terry
      K. Spencer
                2008
                
                $
                249,687
                
                
                $
                206,874
                
                
                $
                -
                
                
                $
                179,291
                
                
                $
                66,818
                
                
                $
                29,720
                
                
                $
                732,390Executive
      Vice President -
                2007
                
                $
                261,354
                
                
                $
                185,535
                
                
                $
                -
                
                
                $
                340,000
                
                
                $
                55,580
                
                
                $
                14,233
                
                
                $
                856,702Natural
      Gas Liquids
                2006
                
                $
                215,000
                
                
                $
                268,524
                
                
                $
                536
                
                
                $
                215,000
                
                
                $
                42,024
                
                
                $
                13,924
                
                
                $
                755,008





(1)
            The
      amounts included in the table reflect the expense allocated to and
      recognized by us in 2006, 2007 and 2008 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,” (FAS Statement 123R).  Material assumptions used in
      the calculation of the value of these equity grants are included in Note N
      to the ONEOK audited financial statements for the year ended December 31,
      2008, included in the ONEOK 2008 Annual Report on Form 10-K filed with the
      SEC on February 24, 2009.





The fair
value of restricted stock and restricted stock incentive units for the purposes
of FAS 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, 2007 and 2008, the grant date fair value for the purposes of FAS
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 each of the referenced peer group
companies.









(2)
            No
      options were granted by ONEOK in 2007 or 2008.  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 FAS Statement
      123R.  Material assumptions used in the calculation of the value
      of option grants are included in Note N to the ONEOK audited financial
      statements for the year ended December 31, 2008, included in the ONEOK
      2008 Annual Report on Form 10-K filed with the SEC on February 24,
      2009.





(3)
            Reflects
      the amounts allocated to and paid by us in 2006, 2007 and 2008 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 ONEOK annual officer incentive
      plan, see “Components of Compensation - Annual Cash Compensation” in
      the ONEOK 2009 Proxy Statement.





(4)
            Reflects
      the portion of the aggregate current year change in pension values and
      above market earnings on nonqualified deferred compensation allocated to
      us for each named executive officer.  For a discussion of the
      Retirement Plan for Employees of ONEOK,


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Inc.
      and Subsidiaries, the ONEOK, Inc. 2005 Supplemental Executive Retirement
      Plan, and the ONEOK Nonqualified Deferred Compensation Plan, see the ONEOK
      2009 Proxy Statement.  The present value is based on the earliest age
      for which an unreducedbenefit is available (age 62) and assumptions from
      the September 30, 2007 and 2006 and December 31, 2008, measurement dates
      for the ONEOK pension plan.





Due to
the fact that in 2008 ONEOK changed its pension plan measurement date, for
financial accounting purposes, from September 30 of each year to December 31,
the allocated amounts included in the Summary Compensation Table with respect to
the Retirement Plan for Employees of ONEOK, Inc. and Subsidiaries and the ONEOK,
Inc. 2005 Supplemental Executive Retirement Plan are twelve-fifteenths of the
allocated amounts that were earned over the 15-month period ending on December
31, 2008.





The
allocated portion of the change in pension value and nonqualified deferred
compensation earnings amounts for Messrs. Gibson, Kneale, Dinan, and Norton for
2006 and 2007 have been adjusted to include only the change in the pension value
based on the present value using the RP2000 mortality tables projected to 2010
and exclude any ONEOK Nonqualified Deferred Compensation Plan earnings that were
not above market earnings.  For 2007, the allocated incremental change in
net present value for Messrs. Gibson, Kneale, Dinan and Norton were $505,584,
$420,392, $20,825 and $39,437, respectively.  For 2006, the allocated
incremental change in net present value for Messrs. Gibson, Kneale and Norton
were $483,616, $261,634 and $35,725, respectively.





In the
Summary Compensation Table for Fiscal 2008 above, only our allocated portion of
the above-market earnings for 2006 and 2007 are included.  For 2006
and 2007, these allocated amounts are $394 and $765 for
Mr. Kneale.  No other ONEOK named executive officers received
above market earnings in 2006 and 2007.  No ONEOK named executive
officers received above market earnings in 2008.  For additional
information on the ONEOK Nonqualified Deferred Compensation Plan, see “Long-Term
Compensation Plans-Nonqualified Deferred Compensation Plan” in the ONEOK 2009
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
      both the ONEOK, Inc.  Nonqualified Deferred Compensation Plan
      and the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries, as
      follows:




Name
                                  Year
                                  
                                  Match
      Under Nonqualified Deferred Compensation
                                    Plan
      (a)
                                  
                                  Match
      Under
                                    Thrift
      Plan (b)John
      W. Gibson
                                  2008
                                  
                                  $
                                  55,336
                                  
                                  $
                                  7,4002007
                                  
                                  $
                                  30,070
                                  
                                  $
                                  6,4442006
                                  
                                  $
                                  33,075
                                  
                                  $
                                  9,900James
      C. Kneale
                                  2008
                                  
                                  $
                                  38,124
                                  
                                  $
                                  7,4002007
                                  
                                  $
                                  26,347
                                  
                                  $
                                  6,4442006
                                  
                                  $
                                  16,455
                                  
                                  $
                                  4,795Curtis
      L. Dinan
                                  2008
                                  
                                  $
                                  17,695
                                  
                                  $
                                  7,4002007
                                  
                                  $
                                  6,873
                                  
                                  $
                                  6,4442006
                                  
                                  $
                                  3,550
                                  
                                  $
                                  4,733Pierce
      H. Norton II
                                  2008
                                  
                                  $
                                  18,963
                                  
                                  $
                                  9,8972007
                                  
                                  $
                                  -
                                  
                                  $
                                  13,5002006
                                  
                                  $
                                  -
                                  
                                  $
                                  13,200Terry
      K. Spencer
                                  2008
                                  
                                  $
                                  19,823
                                  
                                  $
                                  9,8972007
                                  
                                  $
                                  -
                                  
                                  $
                                  13,5002006
                                  
                                  $
                                  -
                                  
                                  $
                                  13,200




(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 2009
  Proxy.





(b)
            The
      Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries is a tax
      qualified plan that 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.





In 2008,
Messrs. Gibson and Kneale received tax gross ups with respect to income imputed
to each of them under the Internal Revenue Code in connection with travel by
their spouses on ONEOK’s aircraft, of which $455 and $8, respectively, were
allocated to us.





The named
executive officers did not receive perquisites or other personal benefits with
an aggregate value of $10,000 or more in 2006, 2007 and 2008, except for Mr.
Gibson with respect to whom we were allocated $31,006 of a country club
membership fee in 2007.


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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:


·
            exercise
      rights applicable to retirees with respect to each outstanding and vested
      stock option granted under the ONEOK LTI
Plan;


·
            receive
      a prorated portion of each outstanding performance unit granted under the
      ONEOK Equity Compensation Plan upon the completion of the performance
      period;


·
            receive
      a prorated portion of each outstanding restricted stock incentive unit
      granted under the ONEOK Equity Compensation Plan upon completion of the
      restricted period; and


·
            receive
      ONEOK health and life benefits for the retiree and qualifying
      dependents.





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 applicable benefits under ONEOK’s disability plan
or payments under ONEOK’s life insurance plan.





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 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.  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.  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, we believe the potential benefits payable upon
a change in control under these agreements are comparatively minor.





Under the
termination agreements, all change in control benefits are “double
trigger.”  Payments and benefits under these 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, Norton and Spencer 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 short-term incentive payment received in the
prior year or the officer’s target short-term incentive payment 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, Norton and Spencer 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 and other
benefits due constitute “excess parachute payments” under applicable tax
law.  For Messrs. Dinan, Norton and Spencer, 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;


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


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


·
            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 our allocated portion
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, 2008, and are estimates of the allocated 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,
Messrs. Gibson and Kneale hold outstanding exercisable options with an allocated
value of $189,857 and $82,039, respectively, as of December 31,
2008.




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John
      W. GibsonBenefit
                                    
                                    Termination
      Upon
                                      Death,
      Disability, or Retirement
                                    
                                    
                                    Termination
                                      Without
      Cause
                                    
                                    
                                    Qualifying
      Termination Following a Change in ControlCash
      Severance
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    3,277,755EquityRestricted
      Stock/Units
                                    
                                    $
                                    1,250,888
                                    
                                    
                                    $
                                    1,250,888
                                    
                                    
                                    $
                                    2,936,868Performance
      Shares/Units
                                    
                                    $
                                    277,598
                                    
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    1,558,172Total
                                    
                                    $
                                    1,528,486
                                    
                                    
                                    $
                                    1,250,888
                                    
                                    
                                    $
                                    4,495,040Other
      BenefitsHealth
      & Welfare
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    11,379Tax
      Gross-Ups
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    3,501,021Total
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    -
                                    
                                    
                                    $
                                    3,512,400Total
                                    
                                    
                                    $
                                    1,528,486
                                    
                                    
                                    $
                                    1,250,888
                                    
                                    
                                    $
                                    11,285,195






James
      C. KnealeBenefit
                                                
                                                Termination
      Upon
                                                  Death,
      Disability, or Retirement
                                                
                                                
                                                
                                                Termination
                                                  Without
      Cause
                                                
                                                
                                                Qualifying
      Termination Following a Change in ControlCash
      Severance
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                
                                                -
                                                
                                                
                                                $
                                                2,378,474EquityRestricted
      Stock/Units
                                                
                                                $
                                                1,032,889
                                                
                                                
                                                $
                                                
                                                1,032,889
                                                
                                                
                                                $
                                                1,174,747Performance
      Shares/Units
                                                
                                                $
                                                277,598
                                                
                                                
                                                
                                                
                                                -
                                                
                                                
                                                $
                                                987,114Total
                                                
                                                $
                                                1,310,487
                                                
                                                
                                                $
                                                
                                                1,032,889
                                                
                                                
                                                $
                                                2,161,861Other
      BenefitsHealth
      & Welfare
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                
                                                -
                                                
                                                
                                                $
                                                11,379Tax
      Gross-Ups
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                
                                                -
                                                
                                                
                                                $
                                                2,043,655Total
                                                
                                                $
                                                -
                                                
                                                
                                                $
                                                
                                                -
                                                
                                                
                                                $
                                                2,055,034Total
                                                
                                                
                                                $
                                                1,310,487
                                                
                                                
                                                $
                                                
                                                1,032,889
                                                
                                                
                                                $
                                                6,595,369







Curtis
      L. DinanBenefit
                                      
                                      Termination
      Upon
                                        Death,
      Disability, or Retirement
                                      
                                      
                                      Termination
                                        Without
      Cause
                                      
                                      
                                      Qualifying
      Termination Following a Change in ControlCash
      Severance
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      874,068EquityRestricted
      Stock/Units
                                      
                                      $
                                      82,667
                                      
                                      
                                      $
                                      82,667
                                      
                                      
                                      $
                                      137,054Performance
      Shares/Units
                                      
                                      $
                                      63,451
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      432,372Total
                                      
                                      $
                                      146,118
                                      
                                      
                                      $
                                      82,667
                                      
                                      
                                      $
                                      569,426Other
      BenefitsHealth
      & Welfare
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      11,047Tax
      Gross-Ups
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -Total
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      11,047Total
                                      
                                      
                                      $
                                      146,118
                                      
                                      
                                      $
                                      82,667
                                      
                                      
                                      $
                                      1,454,541




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Pierce
      H. Norton IIBenefit
                                      
                                      Termination
      Upon
                                        Death,
      Disability, or Retirement
                                      
                                      
                                      Termination
                                        Without
      Cause
                                      
                                      
                                      Qualifying
      Termination Following a Change in ControlCash
      Severance
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      751,576EquityRestricted
      Stock/Units
                                      
                                      $
                                      71,201
                                      
                                      
                                      $
                                      71,201
                                      
                                      
                                      $
                                      99,527Performance
      Shares/Units
                                      
                                      $
                                      71,382
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      257,792Total
                                      
                                      $
                                      142,583
                                      
                                      
                                      $
                                      71,201
                                      
                                      
                                      $
                                      357,319Other
      BenefitsHealth
      & Welfare
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      11,047Tax
      Gross-Ups
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -Total
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      $
                                      11,047Total
                                      
                                      
                                      $
                                      142,583
                                      
                                      
                                      $
                                      71,201
                                      
                                      
                                      $
                                      1,119,942




Terry
      K. SpencerBenefit
                                        
                                        Termination
      Upon
                                          Death,
      Disability, or Retirement
                                        
                                        
                                        Termination
                                          Without
      Cause
                                        
                                        
                                        Qualifying
      Termination Following a Change in ControlCash
      Severance
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        773,988EquityRestricted
      Stock/Units
                                        
                                        $
                                        71,201
                                        
                                        
                                        $
                                        71,201
                                        
                                        
                                        $
                                        99,527Performance
      Shares/Units
                                        
                                        $
                                        71,382
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        257,792Total
                                        
                                        $
                                        142,583
                                        
                                        
                                        $
                                        71,201
                                        
                                        
                                        $
                                        357,319Other
      BenefitsHealth
      & Welfare
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        11,047Tax
      Gross-Ups
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -Total
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        11,047Total
                                        
                                        
                                        $
                                        142,583
                                        
                                        
                                        $
                                        71,201
                                        
                                        
                                        $
                                        1,142,354


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ITEM
      12.
            SECURITYOWNERSHIP 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, 2009, 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
                                          of
      Beneficial Owner (1)
                                        
                                        Common
                                          Units
                                        
                                        
                                        Percent
      of Common
                                          Units
                                        
                                        
                                        Class
      B
                                          Units
                                        
                                        
                                        Percent
      of Class B
                                          Units
                                        
                                        
                                        Percent
      of
                                          All
      Units
                                        
                                        
                                        ONEOK
                                          Shares
      (2)
                                        
                                        
                                        
                                        Percent
      of ONEOK
                                          SharesJohn
      W. Gibson
                                        
                                        
                                        10,000
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        177,929
                                        
                                        (3)
                                        
                                        
                                        *James
      C. Kneale
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        248,705
                                        
                                        (4)
                                        
                                        
                                        *Curtis
      L. Dinan
                                        
                                        
                                        2,000
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        22,162
                                        
                                        
                                        
                                        
                                        *Pierce
      H. Norton II
                                        
                                        
                                        6,778
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        11,819
                                        
                                        
                                        
                                        
                                        *Terry
      K. Spencer
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        18,478
                                        
                                        (5)
                                        
                                        
                                        *Gary
      N. Petersen
                                        
                                        
                                        8,392
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        -Gerald
      B. Smith
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        -Gil
      J. Van Lunsen
                                        
                                        
                                        500
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        -All
      directors and executive officers as a group.
                                        
                                        
                                        27,670
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        *
                                        
                                        
                                        
                                        479,093
                                        
                                        
                                        
                                        
                                        *ONEOK,
      Inc. and affiliates
                                        
                                        
                                        5,900,000
                                        
                                        
                                        
                                        10.8
                                        
                                        
                                        
                                        36,494,126
                                        
                                        
                                        
                                        100
                                        
                                        
                                        
                                        46.6
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        -*
      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, 2009, upon exercise of stock options granted
      under the LTI Plan.(3) Includes
      options for 59,948 shares exercisable within 60 days of February 1,
      2009.(4) Includes
      options for 59,932 shares exercisable within 60 days of February 1,
      2009.(5) Includes
      options for 5,500 shares exercisable within 60 days of February 1,
      2009.


ITEM
      13.
              CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCE


Related-Person
Transactions





The Board
of Directors of our general partner recognizes that transactions between us and
related persons (ONEOK and its subsidiaries and 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 and our unitholders’ best interests 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, our general partner or any member of the Board of
Directors of our general partner may, but are not obligated to, present such
transaction to our Audit Committee 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.  The Board of Directors of our general partner 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 the Board of Directors of our general partner and
our Audit Committee.




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
76.
 - 104
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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 with ONEOK include the following.





Cash Distributions-ONEOK
and its affiliates own all of the Class B units, 5,900,000 common units and the
entire 2 percent general partner interest in us, which, together constituted a
47.7 percent ownership interest in us at December 31, 2008.  For 2008,
we declared total cash distributions to ONEOK of $266.1 million, which included
$76.0 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 2008,
the aggregate amount charged by ONEOK, NBP Services and their affiliates to us
for their services was approximately $181.2 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
these operating agreements.





Transportation Agreements-OES,
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 in Northern Border Pipeline which owns the pipeline.  In
2008, 1.4 percent of Northern Border Pipeline’s design capacity was contracted
on a firm basis with OES.  Revenue from OES for 2008 was $5.0
million.  As of January 31, 2009, 1.4 percent of Northern Border
Pipeline’s design capacity was contracted on a firm basis with OES for
2009.





Our
Natural Gas Gathering and Processing segment sold $627.8 million of natural gas
to ONEOK and its subsidiaries during 2008.  Of our Natural Gas
Pipelines segment’s revenues, $117.1 million were from ONEOK and its
subsidiaries during 2008 for both transportation and storage
services.





Our
Natural Gas Gathering and Processing segment and Natural Gas Liquids Gathering
and Fractionation segment purchase a portion of the natural gas used in their
operations from ONEOK and its subsidiaries.  In 2008, the aggregate
amount charged by ONEOK and its affiliates to us for their services was
approximately $108 million.





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.  In 2008, the aggregate amount charged by ONEOK and
its affiliates related to the Bushton Plant was approximately $10.6
million.





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.  We
have an indemnification agreement with ONEOK Energy Services


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Company,
L.P. (OES) that indemnifies and holds OES harmless from any liability OES may
incur solely as a result of entering into financial hedges on our
behalf.  See Note D 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.





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.





In
addition, ONEOK Partners GP and TransCanada’s affiliate entered into a
transition services agreement for the transfer of the operator function from
ONEOK Partners GP to the affiliate of TransCanada 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 and 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;
      and


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





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





ITEM
14.                          PRINCIPAL
ACCOUNTING FEES AND SERVICES





Audit
and Non-Audit Fees





Audit
services provided by PricewaterhouseCoopers LLP during the 2008 and 2007 fiscal
years 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 by
PricewaterhouseCoopers LLP for the audit of annual consolidated financial
statements for the years ended December 31, 2008 and 2007, and fees billed for
other services rendered by PricewaterhouseCoopers LLP during that
period.




2008
                                            
                                            
                                            2007Audit
      fees (1)
                                            
                                            $
                                            1,320,179
                                            
                                            
                                            $
                                            1,194,070Audit-related
      fees
                                            
                                            
                                            -
                                            
                                            
                                            
                                            -Tax
      fees (2)
                                            
                                            
                                            730,923
                                            
                                            
                                            
                                            950,342All
      other fees (3)
                                            
                                            
                                            35,770
                                            
                                            
                                            
                                            750Total
                                            
                                            $
                                            2,086,872
                                            
                                            
                                            $
                                            2,145,162





(1)
            Audit
      fees consisted of work performed in the audit of our 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)
            Tax
      fees consisted of fees for tax compliance, tax planning, or tax services,
      including preparation of our K-1
statements.


(3)
            All
      other fees consisted of fees for professional education
      seminars.





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 2009
audit, a plan was submitted to and approved by the Audit Committee setting forth
the services expected to be rendered during 2009 for each of the following four
categories for its approval:


(1)
            audit
      services comprised of work performed in the audit of our 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 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.


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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) 
      Financial Statements
              Page
      No.


(a)
            Reports
      of Independent Registered Public Accounting Firms
            62-63





(b)
            Consolidated
      Statements of Income for the years ended
            65


December
31, 2008, 2007 and 2006





(c)
            Consolidated
      Balance Sheets as of December 31, 2008 and 2007
            66





(d)
            Consolidated
      Statements of Cash Flows for the years ended
            67


December
31, 2008, 2007 and 2006





(e)
            Consolidated
      Statements of Changes in Partners’ Equity and Comprehensive
      Income
            68-69


for the
years ended December 31, 2008, 2007 and 2006





(f)
            Notes
      to Consolidated Financial Statements
            70-92




(2) 
      Financial Statement Schedules


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





(3)  Exhibits





3.0
            Not
      used.





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


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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)).





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


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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
            Not
      used.





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
            Not
      used.





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
            Not
      used.





10.9
            Not
      used.





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


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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)).





10.13
            Underwriting
      Agreement dated March 11, 2008, among ONEOK Partners, L.P. and the
      underwriters named therein (incorporated by reference to Exhibit 1.1 to
      ONEOK Partners, L.P.’s report on Form 8-K filed on March 12,
      2008).





10.14
            Common
      Unit Purchase Agreement dated March 11, 2008, between ONEOK Partners, L.P.
      and ONEOK, Inc. (incorporated by reference to Exhibit 1.2 to ONEOK
      Partners, L.P.’s report on Form 8-K filed on March 12,
    2008).





12
            Computation
      of Ratio of Earnings to Fixed Charges for the years ended December 31,
      2008, 2007, 2006, 2005 and 2004.





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.





23.1
            Consent
      of Independent Registered Public Accounting Firm - PricewaterhouseCoopers
      LLP.





23.2
            Consent
      of Independent Registered Public Accounting Firm - KPMG
    LLP.





23.3
            Consent
      of Independent Registered Public Accounting Firm - PricewaterhouseCoopers
      LLP for Exhibit 99.1.





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)).





99.1
            Audited
      balance sheet and related notes of ONEOK Partners GP, L.L.C. as of
      December 31, 2008.





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 SEC, to furnish
copies of any or all of such instruments to the SEC.


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Signatures





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





ONEOK
Partners, L.P.


By: ONEOK
Partners GP, L.L.C., its General Partner





Date:
February 24,
2009                                                                                                                                               
By: /s/ Curtis L.
Dinan
 Curtis L. Dinan
 Executive Vice President,
 Chief Financial Officer and Treasurer
 (Signing on behalf of the Registrant
 and as Principal Financial Officer)





Pursuant
to the requirements of the Exchange Act, this report has been signed below by
the following persons on behalf of the registrant and in the capacities
indicated on this 24th day of February 2009.





/s/
      John W. Gibson
            
            
            /s/
      Caron A. LawhornJohn
      W. Gibson
            
            
            Caron
      A. LawhornChairman
      of the Board and
            
            
            Senior
      Vice President andChief
      Executive Officer
            
            
            Chief
      Accounting Officer/s/
      Curtis L. Dinan
            
            
            /s/
      Jim KnealeCurtis
      L. Dinan
            
            
            Jim
      KnealeDirector
            
            
            Director/s/
      Gil J. Van Lunsen
            
            
            /s/
      Gary N. PetersenGil
      J. Van Lunsen
            
            
            Gary
      N. PetersenDirector
            
            
            Director/s/
      Gerald B. SmithGerald
      B. SmithDirector






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