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EX-32.2 - SECTION 906 CERTIFICATION OF CURTIS L. DINAN - ONEOK Partners LPex_32-2.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

X Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2010
OR
___ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from __________ to __________.


Commission file number   1-12202

 
 

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


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes __ No __

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer X             Accelerated filer __             Non-accelerated filer __             Smaller reporting company__

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes __ No X

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 April 22, 2010
Common units
     
65,413,677 units
Class B units
     
36,494,126 units


 
 

 

ONEOK PARTNERS, L.P.
TABLE OF CONTENTS

Part I.
Financial Information
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part II.
Other Information
 
 
 
 
 
 
 
 
 
 
 
 
As used in this Quarterly Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements.  Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.  Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved.  Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Forward-Looking Statements” and Part II, Item 1A, “Risk Factors” in this Quarterly Report and under Part 1, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEB SITE

We make available on our Web site copies of our Annual Report, Quarterly Reports, 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.  Our Web site and any contents thereof are not incorporated by reference into this report.

We also make available on our Web site the Interactive Data Files voluntarily submitted as Exhibit 101 to this Quarterly Report.  In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

 
 
 
GLOSSARY
The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:

 
AFUDC
Allowance for funds used during construction
 
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2009
 
ASU
Accounting Standards Update
 
Bbl
Barrels, one 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
 
Btu(s)
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
 
Clean Air Act
Federal Clean Air Act, as amended
 
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
 
EBITDA
Earnings before interest, taxes, depreciation and amortization
 
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
 
GAAP
Accounting principles generally accepted in the United States of America
 
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary
     of ONEOK Partners, L.P.
 
KCC
LIBOR
Kansas Corporation Commission
London Interbank Offered Rate
 
MBbl
Thousand barrels
 
MBbl/d
Thousand barrels per day
 
MMBbl
Million barrels
 
MMBtu
Million British thermal units
 
MMBtu/d
Million British thermal units per day
 
MMcf/d
Million cubic feet per day
 
Moody’s
Moody’s Investors Service, Inc.
 
NBP Services
NBP Services, LLC, a wholly owned subsidiary of ONEOK
 
NGL products
Marketable natural gas liquid purity products, such as ethane, ethane/propane
     mix, propane, iso-butane, normal butane and natural gasoline
 
NGL(s)
Natural gas liquid(s)
 
Northern Border Pipeline
Northern Border Pipeline Company
 
NYMEX
New York Mercantile Exchange
 
OBPI
ONEOK Bushton Processing Inc.
 
OCC
Oklahoma Corporation Commission
 
ONEOK
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
 
Partnership Agreement
Third Amended and Restated Agreement of Limited Partnership of ONEOK
     Partners, L.P., as amended
 
Partnership Credit Agreement
The Partnership’s $1.0 billion Amended and Restated Revolving Credit
     Agreement dated March 30, 2007
 
POP                                                      
Percent of proceeds
 
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
 
S&P
Standard & Poor’s Rating Group
 
SEC
Securities and Exchange Commission
 
Securities Act
Securities Act of 1933, as amended
 
XBRL
eXtensible Business Reporting Language
 

 


 
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PART I - FINANCIAL INFORMATION
           
ITEM 1.  FINANCIAL STATEMENTS
           
ONEOK Partners, L.P. and Subsidiaries
           
CONSOLIDATED STATEMENTS OF INCOME
           
   
Three Months Ended
 
   
March 31,
 
(Unaudited)
 
2010
   
2009
 
   
(Thousands of dollars, except per unit amounts)
 
             
Revenues
  $ 2,204,006     $ 1,250,865  
Cost of sales and fuel
    1,942,881       997,324  
Net margin
    261,125       253,541  
Operating expenses
               
Operations and maintenance
    87,205       77,679  
Depreciation and amortization
    43,871       39,940  
General taxes
    9,101       11,767  
Total operating expenses
    140,177       129,386  
Gain (loss) on sale of assets
    (786 )     664  
Operating income
    120,162       124,819  
Equity earnings from investments (Note I)
    21,116       21,222  
Allowance for equity funds used during construction
    247       9,003  
Other income
    1,850       391  
Other expense
    (342 )     (2,046 )
Interest expense
    (54,153 )     (50,908 )
Income before income taxes
    88,880       102,481  
Income taxes
    (4,860 )     (2,871 )
Net income
    84,020       99,610  
Less: Net income attributable to noncontrolling interests
    152       19  
Net income attributable to ONEOK Partners, L.P.
  $ 83,868     $ 99,591  
                 
Limited partners' interest in net income:
               
Net income attributable to ONEOK Partners, L.P.
  $ 83,868     $ 99,591  
General partner's interest in net income
    (27,387 )     (22,312 )
Limited partners' interest in net income
  $ 56,481     $ 77,279  
                 
Limited partners' net income per unit, basic and diluted (Note J)
  $ 0.57     $ 0.85  
                 
Number of units used in computation (thousands)
    99,721       90,920  
See accompanying Notes to Consolidated Financial Statements.
               

 


ONEOK Partners, L.P. and Subsidiaries
           
CONSOLIDATED BALANCE SHEETS
           
   
March 31,
   
December 31,
 
(Unaudited)
 
2010
   
2009
 
Assets
 
(Thousands of dollars)
 
Current assets
           
Cash and cash equivalents
  $ 5,379     $ 3,151  
Accounts receivable, net
    451,811       624,635  
Affiliate receivables
    33,935       32,397  
Gas and natural gas liquids in storage
    219,349       217,585  
Commodity imbalances
    98,011       188,177  
Other current assets
    44,802       36,148  
Total current assets
    853,287       1,102,093  
                 
Property, plant and equipment
               
Property, plant and equipment
    6,385,176       6,353,909  
Accumulated depreciation and amortization
    1,011,304       972,497  
Net property, plant and equipment
    5,373,872       5,381,412  
                 
Investments and other assets
               
Investments in unconsolidated affiliates
    762,435       765,163  
Goodwill and intangible assets
    666,953       668,870  
Other assets
    40,822       35,721  
Total investments and other assets
    1,470,210       1,469,754  
Total assets
  $ 7,697,369     $ 7,953,259  
                 
Liabilities and partners' equity
               
Current liabilities
               
Current maturities of long-term debt
  $ 486,931     $ 261,931  
Notes payable (Note E)
    310,000       523,000  
Accounts payable
    519,675       694,290  
Affiliate payables
    16,983       21,866  
Commodity imbalances
    245,964       392,688  
Other current liabilities
    124,732       153,539  
Total current liabilities
    1,704,285       2,047,314  
                 
Long-term debt, excluding current maturities
    2,593,157       2,822,086  
                 
Deferred credits and other liabilities
    79,404       73,798  
                 
Commitments and contingencies (Note G)
               
                 
Partners' equity
               
ONEOK Partners, L.P. partners’ equity:
               
General partner
    92,602       84,434  
Common units: 65,413,677 and 59,912,777 units issued and outstanding at
   March 31, 2010 and December 31, 2009, respectively
    1,854,011       1,561,762  
Class B units: 36,494,126 units issued and outstanding at
   March 31, 2010 and December 31, 2009
    1,361,205       1,380,299  
Accumulated other comprehensive income (loss) (Note D)
    7,318       (22,037 )
Total ONEOK Partners, L.P. partners' equity
    3,315,136       3,004,458  
                 
Noncontrolling interests in consolidated subsidiaries
    5,387       5,603  
                 
Total partners' equity
    3,320,523       3,010,061  
Total liabilities and partners' equity
  $ 7,697,369     $ 7,953,259  
See accompanying Notes to Consolidated Financial Statements.
 

 
 

ONEOK Partners, L.P. and Subsidiaries
           
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Three Months Ended
 
   
March 31,
 
(Unaudited)
 
2010
   
2009
 
 
(Thousands of dollars)
 
Operating activities
           
Net income
  $ 84,020     $ 99,610  
Depreciation and amortization
    43,871       39,940  
Allowance for equity funds used during construction
    (247 )     (9,003 )
Loss (gain) on sale of assets
    786       (664 )
Deferred income taxes
    1,239       1,706  
Equity earnings from investments
    (21,116 )     (21,222 )
Distributions received from unconsolidated affiliates
    21,998       25,187  
Changes in assets and liabilities:
               
Accounts receivable
    172,824       11,224  
Affiliate receivables
    (1,538 )     4,880  
Gas and natural gas liquids in storage
    (1,764 )     44,641  
Accounts payable
    (168,406 )     (65,065 )
Affiliate payables
    (4,883 )     (4,961 )
Commodity imbalances, net
    (56,558 )     (59,078 )
Accrued interest
    23,045       33,555  
Other assets and liabilities
    (37,792 )     (25,974 )
Cash provided by operating activities
    55,479       74,776  
                 
Investing activities
               
Changes in investments in unconsolidated affiliates
    1,334       3,362  
Capital expenditures (less allowance for equity funds used during construction)
    (35,827 )     (192,494 )
Proceeds from sale of assets
    138       1,083  
Cash used in investing activities
    (34,355 )     (188,049 )
                 
Financing activities
               
Cash distributions:
               
General and limited partners
    (132,086 )     (120,932 )
Noncontrolling interests
    (368 )     (343 )
Borrowing (repayment) of notes payable, net
    (213,000 )     36,700  
Repayment of notes payable with maturities over 90 days
    -       (470,000 )
Issuance of long-term debt, net of discounts
    -       498,325  
Long-term debt financing costs
    -       (4,000 )
Repayment of long-term debt
    (2,983 )     (2,983 )
Issuance of common units, net of discounts
    322,721       -  
Contribution from general partner
    6,820       -  
Cash used in financing activities
    (18,896 )     (63,233 )
Change in cash and cash equivalents
    2,228       (176,506 )
Cash and cash equivalents at beginning of period
    3,151       177,635  
Cash and cash equivalents at end of period
  $ 5,379     $ 1,129  
See accompanying Notes to Consolidated Financial Statements.
 

 

 
ONEOK Partners, L.P. and Subsidiaries
                   
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
 
                         
                         
   
ONEOK Partners, L.P. Partners' Equity
 
                         
                         
     
Common
     
Class B
     
General
     
Common
 
(Unaudited)
  Units      Units     Partner    
Units
 
   
(Units)
 
(Thousands of dollars)
 
                         
December 31, 2009
    59,912,777       36,494,126     $ 84,434     $ 1,561,762  
Net income
    -       -       27,387       35,432  
Other comprehensive income (Note D)
    -       -       -       -  
Issuance of common units (Note F)
    5,500,900       -       -       322,721  
Contribution from general partner (Note F)
    -       -       6,820       -  
Distributions paid (Note F)
    -       -       (26,039 )     (65,904 )
March 31, 2010
    65,413,677       36,494,126     $ 92,602     $ 1,854,011  
See accompanying Notes to Consolidated Financial Statements.
         

 


ONEOK Partners, L.P. and Subsidiaries
                   
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
 
(Continued)
                       
                         
     ONEOK Partners, L.P. Partners' Equity            
            Accumulated      Noncontrolling        
           Other    
Interests in
       
   
Class B
    Comprehensive     Consolidated     Total Partners'  
(Unaudited)
  Units     Income (Loss)     Subsidiaries      Equity  
   
(Thousands of dollars)
 
                         
December 31, 2009
  $ 1,380,299     $ (22,037 )   $ 5,603     $ 3,010,061  
Net income
    21,049       -       152       84,020  
Other comprehensive income (Note D)
    -       29,355       -       29,355  
Issuance of common units (Note F)
    -       -       -       322,721  
Contribution from general partner (Note F)
    -       -       -       6,820  
Distributions paid (Note F)
    (40,143 )     -       (368 )     (132,454 )
March 31, 2010
  $ 1,361,205     $ 7,318     $ 5,387     $ 3,320,523  
                                 
 

 
 
ONEOK Partners, L.P. and Subsidiaries
           
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
           
             
   
Three Months Ended
 
   
March 31,
 
(Unaudited)
 
2010
   
2009
 
   
(Thousands of dollars)
 
             
Net income
  $ 84,020     $ 99,610  
Other comprehensive income (loss) (Note D)
    29,355       (19,199 )
Comprehensive income
    113,375       80,411  
Less: Comprehensive income attributable to noncontrolling interests
    152       19  
Comprehensive income attributable to ONEOK Partners, L.P.
  $ 113,223     $ 80,392  
See accompanying Notes to Consolidated Financial Statements.
               
 
 
 
 
ONEOK Partners, L.P. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

A.           SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented.  All such adjustments are of a normal recurring nature.  The 2009 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Recently Issued Accounting Updates

The following recently issued accounting standards updates affect our consolidated financial statements and related disclosures:

Fair Value Measurements and Disclosures - In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which established new disclosure requirements and clarified existing requirements for disclosures of fair value measurements.  ASU 2010-06 required us to add two new disclosures, when applicable: (i) transfers in and out of Level 1 and 2 fair value measurements including the reasons for the transfers, and (ii) a gross presentation of activity within the reconciliation of Level 3 fair value measurements.  Except for separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements, we applied this guidance to our disclosures beginning with this Quarterly Report.  The separate disclosure of purchases, sales, issuances and settlements will be required beginning with our March 31, 2011, Quarterly Report, and we do not expect the impact to be material.  ASU 2010-06 requires prospective application in the period of adoption, and we have not recast our prior-year disclosures.  See Note B for more discussion of our fair value measurements.

Embedded Credit Derivatives - In March 2010, the FASB issued ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which clarified that disclosures required for credit derivatives do not apply to an embedded derivative’s feature related to the transfer of credit risk that is only in the form of subordination of one financial instrument to another.  This guidance will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statements and related disclosures.

B.           FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of 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 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 prices.  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 using the interest rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and U.S. Treasury swaps.  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.



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

   
March 31, 2010
 
   
Level 1
   
Level 2
   
Level 3
   
Total - Gross
   
Netting (a)
   
Total - Net
 
   
(Thousands of dollars)
 
Derivatives - Commodity
                                   
Assets - Over-the-counter
   Financial Contracts  (b)
  $ -     $ 18,895     $ 2,588     $ 21,483     $ (10,197 )   $ 11,286  
                                                 
Liabilities  - Over-the-counter
   Financial Contracts
  $ -     $ (5,277 )   $ (4,920 )   $ (10,197 )   $ 10,197     $ -  
                                                 
   
December 31, 2009
 
   
Level 1
   
Level 2
   
Level 3
   
Total - Gross
   
Netting (a)
   
Total - Net
 
   
(Thousands of dollars)
 
Derivatives - Commodity
                                               
Assets
  $ -     $ 459     $ -     $ 459     $ (459 )   $ -  
Liabilities (c)
  $ -     $ (5,720 )   $ (13,052 )   $ (18,772 )   $ 459     $ (18,313 )
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.
 
(b) - Included in other current assets in our Consolidated Balance Sheet.
                         
(c) - Included in other current liabilities in our Consolidated Balance Sheet.
                         
 
At March 31, 2010, and December 31, 2009, we had no cash collateral held or posted under our master-netting arrangements.

We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

Our derivative instruments categorized as Level 2 include non-exchange traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively.  Our derivative instruments categorized as Level 3 include over-the-counter fixed-price swaps for purity NGL products and natural gas basis swaps.  These swaps are valued based on information from a pricing service, the forward NYMEX curve for crude oil, correlations of specific NGL purity products to crude oil and internally developed basis curves incorporating observable and unobservable market data.  We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions and day-to-day pricing fluctuations and analysis of historical relationships of data from the pricing service compared with actual settlements and correlations.  We do not believe that our derivative instruments categorized as Level 3 have a material impact on our results of operations, as the majority of our derivatives are accounted for as cash flow hedges for which ineffectiveness is not material.

The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
 
   
Three Months Ended
 
   
March 31,
 
Derivative Assets (Liabilities)
 
2010
   
2009
 
   
(Thousands of dollars)
 
Net assets (liabilities) at beginning of period
  $ (13,052 )   $ 37,649  
   Total realized/unrealized gains (losses):
               
       Included in earnings (a)
    -       1,104  
       Included in other comprehensive income (loss)
    10,720       (12,758 )
Net assets (liabilities) at end of period
  $ (2,332 )   $ 25,995  
(a) - Included in revenues in our Consolidated Statements of Income.
         
 
The change in our Level 3 fair value measurements is due to the execution of new hedge transactions 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.
 
 

 
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items.  The fair value of borrowings under our Partnership Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $3.3 billion at March 31, 2010, and at December 31, 2009.  The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.1 billion at March 31, 2010, and at December 31, 2009.  The estimated fair value of the aggregate of our senior notes outstanding has been determined using quoted market prices for similar issues with similar terms and maturities.

C.           RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold.  We use physical forward sales and financial derivatives to secure a certain price for a portion of our share of natural gas, condensate and NGL products.  We follow established policies and procedures to assess risk and approve, monitor and report our risk management activities.  We have not used these instruments for trading purposes.  We are also subject to the risk of interest-rate fluctuation in the normal course of business.

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate.  We use the following commodity derivative instruments to mitigate the commodity price risk associated with a portion of the forecasted sales of these commodities:
·  
Futures contracts - Standardized exchange-traded contracts to purchase or sell natural gas or crude oil at a specified price, requiring delivery on, or settlement through, the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations; 
·  
Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for delivery at some specified time in the future.  Forward contracts are different from futures in that forwards are customized and non-exchange traded; and
·  
Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity.  In a typical commodity swap, parties exchange payments based on changes in the price of a commodity or a market index, while fixing the price they effectively pay or receive for the physical commodity.  As a result, one party assumes the risks and benefits of the movements in market prices while the other party assumes the risks and benefits of a fixed price for the commodity. 

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of receiving commodities in exchange for services associated with our POP contracts.  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 basis risk between the various production and market locations where we buy and sell commodities.  As part of our hedging strategy, we use the previously described commodity derivative instruments to minimize the impact of price fluctuations related to natural gas, NGLs and condensate.  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.  We hedge a portion of the forecasted sales of the commodities we retain, including NGLs, natural gas and condensate.
 
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 can expose us to commodity price risk depending on the regulatory treatment for this activity.  We use physical forward sales or purchases to reduce the impact of price fluctuations related to natural gas.  At March 31, 2010, and December 31, 2009, we were not using any financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location.  To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas.  We utilize fixed-price physical forward contracts to reduce the impact of price fluctuations related to NGLs.  At March 31, 2010, and December 31, 2009, we were not using any financial derivative instruments with respect to our NGL activities.
 
 

 
Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps.  Interest-rate swaps are agreements to exchange an interest payment at some future point based on the differential between two interest rates.  At March 31, 2010, and December 31, 2009, we did not have any interest-rate swap agreements.

Accounting Treatment - We record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery.  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 cash flow hedging relationship and, if so, the reason for holding it.

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

   
Recognition and Measurement
Accounting Treatment
Balance Sheet
 
Income Statement
Normal purchases and
normal sales
 
- Fair value not recorded
 
 - Change in fair value not recognized in earnings
Mark-to-market
 
- Recorded at fair value
 
 - Change in fair value recognized in earnings
Cash flow hedge
 
- Recorded at fair value
 
 - Ineffective portion of the gain or loss on the
   derivative instrument is recognized in earnings
 
   
- Effective portion of the gain or loss on the
   derivative instrument is reported initially
   as a component of accumulated other
   comprehensive income (loss)
 
 - Effective portion of the gain or loss on the
   derivative instrument is reclassified out of
   accumulated other comprehensive income
   (loss) into earnings when the forecasted
   transaction affects earnings
Fair value hedge
 
- Recorded at fair value
 
- The gain or loss on the derivative instrument
   is recognized in earnings
 
   
- Change in fair value of the hedged item is
   recorded as an adjustment to book value
 
- Change in fair value of the hedged item is
   recognized in earnings

We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness.  We specifically identify the forecasted transaction that has been designated as the hedged item with a cash flow hedge.  We assess the effectiveness of hedging relationships quarterly by performing a regression analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis.  We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

Cash flows from futures, forwards and swaps that are accounted for as hedges are included in the same Consolidated Statement of Cash Flows category as the cash flows from the related hedged items.

Fair Values of Derivative Instruments - See Note B for the fair values of our derivative instruments and a discussion of the inputs associated with our fair value measurements.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:
 
           
March 31,
 
December 31,
         
Contract
2010
 
2009
         
Type
Receiver
 
Receiver
Derivatives designated as hedging instruments:
         
 
Cash flow hedges
           
   
Fixed price
           
     
- Natural gas (Bcf)
Swaps
 
 13.4
 
 9.2
 
     
- Crude oil and NGLs (MMBbl)
Swaps
 
 2.4
 
 2.4
 
   
Basis
           
     
- Natural gas (Bcf)
Swaps
 
 13.4
 
 9.2
 
 
 
 
 
Cash Flow Hedges - At March 31, 2010, our Consolidated Balance Sheet reflected a net unrealized gain of $11.4 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities that will be realized within the next 21 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $5.0 million in gains over the next 12 months, and we will recognize $6.4 million in gains thereafter.

The following table sets forth the effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:

   
Three Months Ended
 
Derivatives in Cash Flow
Hedging Relationships
 
March 31,
 
 
2010
   
2009
 
   
(Thousands of dollars)
 
Commodity contracts
  $ 24,707     $ (331 )
Interest rate contracts
    -       121  
Total gain (loss) recognized in other comprehensive
   income (loss) (effective portion)
  $ 24,707     $ (210 )
                 
The following table sets forth the effect of cash flow hedges on our Consolidated Statements of Income for the periods indicated:

 
Location of Gain (Loss) Reclassified from
 
Three Months Ended
 
Derivatives in Cash Flow
Accumulated Other Comprehensive Income
 
March 31,
 
Hedging Relationships
(Loss) into Net Income (Effective Portion)
 
2010
   
2009
 
     
(Thousands of dollars)
 
Commodity contracts
Revenues
  $ (4,869 )   $ 18,765  
Interest rate contracts
Interest expense
    221       436  
Total gain (loss) reclassified from accumulated other comprehensive
   income (loss) into net income (effective portion)
  $ (4,648 )   $ 19,201  

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2010 and 2009.  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 due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2010 and 2009.

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 from the amortization of terminated swaps for the three months ended March 31, 2010 and 2009, were not material, and the remaining amortization of terminated swaps will be recognized over the following periods.

       
 
(Millions of dollars)
Remainder of 2010
  $ 2.8  
2011
  $ 0.9  

Credit Risk - All the commodity derivative contracts we enter into are with ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK.  OES enters into similar commodity derivative contracts with third parties at our direction and on our behalf.  We have an indemnification agreement with OES that indemnifies and holds OES harmless from any liability they may incur solely as a result of its entering into commodity derivative contracts on our behalf.  Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $11.3 million at March 31, 2010, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors.  At December 31, 2009, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty.



 
D.           OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth other comprehensive income (loss) for the periods indicated:
 
   
Three Months Ended
 
   
March 31,
 
   
2010
     
2009
 
   
(Thousands of dollars)
Unrealized gains (losses) on derivatives
$
 24,707
     $
(210)
 
Less:  Realized gains (losses) on derivatives
recognized in net income
 
 (4,648)
     
 19,201
 
Other
 
 -
     
 212
 
Other comprehensive income (loss)
$
 29,355
     $
(19,199)
 

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets as of March 31, 2010, and December 31, 2009, was attributable to unrealized gains and losses on derivatives.

E.           CREDIT FACILITIES

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants.  Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1.  If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisitions.  At March 31, 2010, our ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

At March 31, 2010, and December 31, 2009, we had $310 million and $523 million, respectively, of borrowings outstanding under our Partnership Credit Agreement, and under the most restrictive provisions of our Partnership Credit Agreement had $558 million and $367 million of credit available, respectively.  At March 31, 2010, and December 31, 2009, we had a total of $24.2 million issued in letters of credit outside of the Partnership Credit Agreement.  Borrowings under our Partnership Credit Agreement are nonrecourse to our general partner.

Borrowings under our Partnership Credit Agreement are typically short term in nature, ranging from one day to six months.  Accordingly, these borrowings are classified as short-term notes payable.

F.           PARTNERS’ EQUITY

ONEOK - ONEOK and its affiliates owned all of the Class B units, 5.9 million common units and the entire 2 percent general partner interest in us, which together constituted a 42.8 percent ownership interest in us at March 31, 2010.

Equity Issuance - In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.

Cash Distributions - Cash distributions paid to our general partner of $26.0 million and $22.7 million in the three months ended March 31, 2010 and 2009, respectively, included incentive distributions of $23.4 million and $20.3 million, respectively.

In April 2010, our general partner declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) for the first quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid on May 14, 2010, to unitholders of record at the close of business on April 30, 2010.



 
G.           COMMITMENTS AND CONTINGENCIES

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 and 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 pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean-up costs, which could materially affect our results of operations and cash flows.  In addition, emission controls required under the 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 could have a material adverse effect on our business, financial condition and results of operations.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect upon earnings or cash flows during the three months ended March 31, 2010 or 2009.

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate it has installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

In addition, the EPA has issued a proposed rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in early 2013.  The proposed rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment.  We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Legal Proceedings - We are a party to various litigation matters and claims that have arisen 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.

Overland Pass Pipeline Company - Overland Pass Pipeline Company is a joint venture between us and a subsidiary of The Williams Companies, Inc. (Williams).  We own 99 percent of the joint venture and operate the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company up to a total of 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 50 percent, Williams would have the option to become operator.  Should Williams exercise its option to obtain a 50 percent ownership interest, we may be required to deconsolidate Overland Pass Pipeline Company and account for it under the equity method of accounting.



 
H.           SEGMENTS

Segment Descriptions - We implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses.  Our financial results are now reported in these three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which consolidates our former natural gas liquids gathering and fractionation segment with our former natural gas liquids pipelines segment, due to the integrated manner in which they are managed.  Prior-period amounts have been recast to reflect these segment changes.

Our operations are divided into three reportable 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 natural gas;
·  
our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities; and
·  
our Natural Gas Liquids segment primarily gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products.

Accounting Policies - The accounting policies of the segments are described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report.  Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers.  Net margin is comprised of total revenues less cost of sales and fuel.  Cost of sales and fuel includes commodity purchases, fuel and transportation costs.

Customers - For the three months ended March 31, 2010 and 2009, we had no single unaffiliated customer from which we received 10 percent or more of our consolidated revenues.

For the three months ended March 31, 2010, sales to affiliated customers were less than 10 percent.  For the three months ended March 31, 2009, sales to affiliated customers were 12 percent of our consolidated revenues.  See Note K for additional information about our sales to affiliated customers.



 
Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:

Three Months Ended
March 31, 2010
 
Natural Gas
Gathering and Processing
   
Natural Gas
Pipelines (a)
   
Natural Gas
Liquids (b)
   
Other and
Eliminations
   
Total
 
   
(Thousands of dollars)
 
Sales to unaffiliated customers
  $ 114,196     $ 57,452     $ 1,895,428     $ (1 )   $ 2,067,075  
Sales to affiliated customers
    107,177       29,754       -       -       136,931  
Intersegment revenues
    133,815       384       7,054       (141,253 )     -  
Total revenues
  $ 355,188     $ 87,590     $ 1,902,482     $ (141,254 )   $ 2,204,006  
                                         
Net margin
  $ 81,315     $ 78,565     $ 104,014     $ (2,769 )   $ 261,125  
Operating costs
    34,456       22,776       41,001       (1,927 )     96,306  
Depreciation and amortization
    14,652       10,882       18,336       1       43,871  
Gain (loss) on sale of assets
    (28 )     1       (758 )     (1 )     (786 )
Operating income
  $ 32,179     $ 44,908     $ 43,919     $ (844 )   $ 120,162  
                                         
Equity earnings from investments
  $ 5,687     $ 15,075     $ 354     $ -     $ 21,116  
Investments in unconsolidated
  affiliates
  $ 324,830     $ 408,585     $ 29,020     $ -     $ 762,435  
Total assets
  $ 1,628,369     $ 1,887,322     $ 4,233,887     $ (52,209 )   $ 7,697,369  
Noncontrolling interests in
  consolidated subsidiaries
  $ -     $ 5,328     $ 44     $ 15     $ 5,387  
Capital expenditures
  $ 19,147     $ 3,235     $ 15,819     $ (2,374 )   $ 35,827  
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.5 million, net margin of $62.2 million and operating income of $34.1 million.
 
 
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $81.6 million, of which $48.8 million related to sales within the segment, net margin of $63.4 million and operating income of $35.3 million.
 
 
Three Months Ended
March 31, 2009
 
Natural Gas
Gathering and Processing
   
Natural Gas
Pipelines (a)
   
Natural Gas
Liquids (b)
   
Other and
Eliminations
   
Total
 
   
(Thousands of dollars)
 
Sales to unaffiliated customers
  $ 62,146     $ 48,717     $ 995,866     $ 1     $ 1,106,730  
Sales to affiliated customers
    118,207       25,928       -       -       144,135  
Intersegment revenues
    69,890       147       5,095       (75,132 )     -  
Total revenues
  $ 250,243     $ 74,792     $ 1,000,961     $ (75,131 )   $ 1,250,865  
                                         
Net margin
  $ 86,052     $ 65,568     $ 102,591     $ (670 )   $ 253,541  
Operating costs
    31,828       20,180       37,627       (189 )     89,446  
Depreciation and amortization
    14,448       12,793       12,697       2       39,940  
Gain (loss) on sale of assets
    (19 )     27       3       653       664  
Operating income
  $ 39,757     $ 32,622     $ 52,270     $ 170     $ 124,819  
                                         
Equity earnings from investments
  $ 4,466     $ 16,208     $ 548     $ -     $ 21,222  
Capital expenditures
  $ 28,818     $ 17,428     $ 146,248     $ -     $ 192,494  
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $61.6 million, net margin of $51.7 million and operating income of $23.3 million.
 
 
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $57.9 million, of which $33.7 million related to sales within the segment, net margin of $43.8 million and operating income of $22.0 million.
 
 


 
I.           UNCONSOLIDATED AFFILIATES

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

   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
   
(Thousands of dollars)
 
Northern Border Pipeline
  $ 14,846     $ 16,038  
Bighorn Gas Gathering, L.L.C.
    237       2,086  
Fort Union Gas Gathering, L.L.C.
    3,558       2,210  
Lost Creek Gathering Company, L.L.C.
    1,402       890  
Other
    1,073       (2 )
Equity earnings from investments
  $ 21,116     $ 21,222  

Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
 
 
Three Months Ended
 
March 31,
   
2010
   
2009
 
 
(Thousands of dollars)
Income Statement
           
Operating revenues
  $ 99,231     $ 106,066  
Operating expenses
  $ 44,715     $ 44,803  
Net income
  $ 46,911     $ 50,516  
                 
Distributions paid to us
  $ 23,529     $ 33,331  

Distributions paid to us are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statement of Cash Flows.  Distributions paid to us include a $1.5 million and $8.1 million return of investment for the three months ended March 31, 2010 and 2009, respectively. 

J.           LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units.  ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B units.  Because ONEOK has waived its right to increased quarterly distributions, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences.  ONEOK retains the option to withdraw its waiver at any time by giving us no less than 90 days advance notice.  ONEOK Partners GP owns the entire 2 percent general partnership interest in us, which entitles it to 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 limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is generally allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income attributable to ONEOK Partners, L.P. 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 distribution allocated to our general partner totaled $25.7 million and $20.3 million for the three months ended March 31, 2010 and 2009, respectively.

The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period.  As such, incentive distribution rights are not allocated on undistributed earnings or distributions in excess of earnings.  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.  For additional information regarding our general partner’s incentive distribution rights, see Note J of the Notes to Consolidated Financial Statements in our Annual Report.

K.           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.  Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchase a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

We have certain contractual rights to the Bushton Plant.  Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services to us 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 costs and expenses necessary for the operation and maintenance of the Bushton Plant, and we reimburse ONEOK for a portion of OBPI’s obligations under equipment leases covering the Bushton Plant.

Under the Services Agreement with ONEOK, ONEOK Partners GP and NBP Services (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 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 operating obligations.

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.  It is not practicable to determine what these general overhead costs would be on a stand-alone basis.  All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

Our derivative contracts with OES are discussed under “Credit Risk” in Note C.

The following table sets forth the transactions with related parties for the periods indicated:
 
 
Three Months Ended
 
March 31,
   
2010
   
2009
 
 
(Thousands of dollars)
Revenues
  $ 136,931     $ 144,135  
                 
Expenses
               
Cost of sales and fuel
  $ 17,759     $ 16,638  
Administrative and general expenses
    51,025       48,623  
Total expenses
  $ 68,784     $ 65,261  

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $72.7 million and $68.5 million in the three months ended March 31, 2010 and 2009, respectively.
 
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report.
 
EXECUTIVE SUMMARY
 
Outlook - We expect a moderate economic recovery in 2010, with inflationary pressures beginning in 2011.  Although recent volatility in the financial markets could limit our access to financial markets on a timely basis or increase our cost of capital in the future, we anticipate improved credit markets during 2010, compared with 2009; however, inflation risks may increase the cost of capital.  We anticipate the consolidation of underperforming assets in the industry, particularly those with high commodity price exposure and/or high levels of debt.  Additionally, we anticipate an improving commodity price environment during 2010, compared with 2009. 

Recent Developments - In April 2010, we announced that we will invest approximately $405 million to $470 million for projects in the Bakken Shale in the Williston Basin in North Dakota and in the Woodford Shale in Oklahoma, which will enable us to meet the rapidly growing needs of producers in these areas.  These investments include construction of a new 100 MMcf/d natural gas processing facility, the Garden Creek plant, in eastern McKenzie County, North Dakota.  The plant and related expansions are estimated to cost between $150 million and $210 million and will double our natural gas processing capacity in the Williston Basin.  These projects are expected to be completed in the fourth quarter of 2011.  In addition, we will invest an additional $200 million to $205 million during 2010 and 2011 for new well connections, expansions and upgrades to our existing natural gas gathering infrastructure in the Bakken Shale.

We will invest an additional $55 million in the Woodford Shale in Oklahoma for new well connections in 2010 and 2011 and to connect our existing gathering system to our existing Maysville, Oklahoma, natural gas processing facility as well as the connection of a new plant to our NGL gathering system.

Equity Issuance - In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.  As a result of these transactions, ONEOK and its subsidiaries own a 42.8 percent aggregate equity interest in us.

Cash Distributions - In April 2010, our general partner declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) for the first quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid May 14, 2010, to unitholders of record at the close of business on April 30, 2010.
 
Segment Realignment - We implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses.  Our financial results are now reported in these three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which consolidates our former natural gas liquids gathering and fractionation segment with our former natural gas liquids pipelines segment, due to the integrated manner in which they are managed.  Prior-period amounts have been recast to reflect these segment changes.

Operating Results - Limited partners’ net income per unit decreased to $0.57 for the three months ended March 31, 2010, compared with $0.85 for the same period in 2009.  The decrease in limited partners’ net income per unit for the three-month period ending March 31, 2010, is due primarily to the following:
·  
an increase in operating costs resulting from the operation of our recently completed capital projects and higher employee-related costs;
·  
a decrease in allowance for equity funds used during construction due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral in our Natural Gas Liquids segment; and
·  
an increase in the number of common units outstanding; offset partially by
·  
an increase in net margin due primarily to:
-  
higher NGL volumes gathered, fractionated and transported, associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections in our Natural Gas Liquids segment;

 

 
-  
higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission in our Natural Gas Pipelines segment; offset partially by
-  
lower optimization margins due to less NGL fractionation and transportation capacity available for optimization in our Natural Gas Liquids segment;
-  
the impact of operational measurement gains and losses as compared with the same period last year; and
-  
lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009 in our Natural Gas Gathering and Processing segment.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report:
·  
ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which did not have a material impact on our consolidated financial statements and related disclosures.  See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements; and
·  
ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statements and related disclosures.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Information about our critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Estimates,” in our Annual Report.


 
 
FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

   
Three Months Ended
   
Variances
 
   
March 31,
   
2010 vs. 2009
 
Financial Results
 
2010
   
2009
   
Increase (Decrease)
 
   
(Millions of dollars)
 
Revenues
  $ 2,204.0     $ 1,250.9     $ 953.1       76 %
Cost of sales and fuel
    1,942.9       997.4       945.5       95 %
Net margin
    261.1       253.5       7.6       3 %
Operating costs
    96.2       89.5       6.7       7 %
Depreciation and amortization
    43.9       39.9       4.0       10 %
Gain (loss) on sale of assets
    (0.8 )     0.7       (1.5 )        *
Operating income
  $ 120.2     $ 124.8     $ (4.6 )     (4 %)
                                 
Equity earnings from investments
  $ 21.1     $ 21.2     $ (0.1 )     (0 %)
Allowance for equity funds used
     during construction
  $ 0.2     $ 9.0     $ (8.8 )     (98 %)
Interest expense
  $ (54.2 )   $ (50.9 )   $ 3.3       6 %
Capital expenditures
  $ 35.8     $ 192.5     $ (156.7 )     (81 %)
* Percentage change is greater than 100 percent.
                         
 
Energy markets were affected by increased commodity prices during the three months ended March 31, 2010, compared with the same period last year.  The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel.  Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due to the following:
·  
higher NGL volumes gathered, fractionated and transported, associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections in our Natural Gas Liquids segment;
·  
higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission in our Natural Gas Pipelines segment; offset partially by
·  
lower optimization margins due to less NGL fractionation and transportation capacity available for optimization in our Natural Gas Liquids segment;
·  
the impact of operational measurement gains and losses as compared with the same period last year; and
·  
lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009 in our Natural Gas Gathering and Processing segment.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the operation of our recently completed capital projects and higher employee-related costs.

Depreciation and amortization increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to higher depreciation expense associated with our completed capital projects.

Allowance for equity funds used during construction decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.
 
Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the completion of our capital projects discussed in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Annual Report.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.



 
Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment’s operations include gathering and processing of natural gas produced from crude oil and natural gas wells.  We gather and process 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 and/or process natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota, and the Powder River Basin of Wyoming.  The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry gas, that does not require processing or NGL extraction, in order to be marketable; dry gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.  The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users.  When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream.  This unfractionated NGL stream is fractionated, through the application of heat and pressure, and separated into NGL products.  Our natural gas and NGL products are sold to affiliates and a diverse customer base.  Revenues for this segment are derived primarily from POP, fee and keep-whole contracts.  Under a POP contract, we retain a portion of sales proceeds from the commodity sales for our services.  With a fee-based contract, we charge a fee for our services, and with the keep-whole contract, we retain the NGLs as our fee for service and return to the producer an equivalent quantity of, or payment for, residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us.

Selected Financial Results - The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:
 
   
Three Months Ended
   
Variances
 
   
March 31,
   
2010 vs. 2009
 
Financial Results
 
2010
   
2009
   
Increase (Decrease)
 
 
(Millions of dollars)
 
NGL and condensate sales
  $ 187.1     $ 117.8     $ 69.3       59 %
Residue gas sales
    131.9       92.0       39.9       43 %
Gathering, compression, dehydration
  and processing fees and other revenue
    36.2       40.5       (4.3 )     (11 %)
Cost of sales and fuel
    273.9       164.2       109.7       67 %
Net margin
    81.3       86.1       (4.8 )     (6 %)
Operating costs
    34.4       31.8       2.6       8 %
Depreciation and amortization
    14.7       14.5       0.2       1 %
Operating income
  $ 32.2     $ 39.8     $ (7.6 )     (19 %)
                                 
Equity earnings from investments
  $ 5.7     $ 4.5     $ 1.2       27 %
Capital expenditures
  $ 19.1     $ 28.8     $ (9.7 )     (34 %)

Net margin decreased for the three months ended March 31, 2010, compared with the same period last year, primarily as result of lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of higher employee-related costs.

Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of our capital projects.



 
Selected Operating Information - The following tables set forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
 
   
Three Months Ended
 
   
March 31,
 
Operating Information
 
2010
   
2009
 
Natural gas gathered (BBtu/d) (a)
    1,092       1,163  
Natural gas processed (BBtu/d) (a)
    664       653  
NGL sales (MBbl/d) (a)
    43       41  
Residue gas sales (BBtu/d) (a)
    275       285  
Realized composite NGL net sales price ($/gallon) (b)
  $ 0.99     $ 0.88  
Realized condensate net sales price ($/Bbl) (b)
  $ 62.39     $ 68.45  
Realized residue gas net sales price ($/MMBtu) (b)
  $ 5.20     $ 3.58  
Realized gross processing spread ($/MMBtu) (a)
  $ 6.37     $ 7.43  
(a) - Includes volumes for consolidated entities only.
               
(b) - Includes equity volumes only.
               
 
   
Three Months Ended
 
   
March 31,
 
Operating Information (a)
 
2010
   
2009
 
Percent of proceeds
           
  Wellhead purchases (MMBtu/d)
    44,586       60,496  
  NGL sales (Bbl/d)
    5,014       5,040  
  Residue gas sales (MMBtu/d)
    38,395       34,819  
  Condensate sales (Bbl/d)
    1,918       2,095  
  Percentage of total net margin
    53%       50%  
Fee-based
               
  Wellhead volumes (MMBtu/d)
    1,092,061       1,163,376  
  Average rate ($/MMBtu)
  $ 0.30     $ 0.28  
  Percentage of total net margin
    36%       35%  
Keep-whole
               
  NGL shrink (MMBtu/d)
    13,819       16,960  
  Plant fuel (MMBtu/d)
    1,714       2,182  
  Condensate shrink (MMBtu/d)
    1,579       1,755  
  Condensate sales (Bbl/d)
    320       355  
  Percentage of total net margin
    11%       15%  
(a) - Includes volumes for consolidated entities only.
               

 

 
Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the remainder of 2010 and for the year ending December 31, 2011, as of April 28, 2010.
 
   
Nine Months Ending
 
   
December 31, 2010
 
   
Volumes
Hedged
    Average Price  
Percentage
Hedged
 
NGLs (Bbl/d) (a)
    5,261     $ 1.04  
/ gallon
    68%  
Condensate (Bbl/d) (a)
    1,648     $ 1.81  
/ gallon
    76%  
Total (Bbl/d)
    6,909     $ 1.22  
/ gallon
    70%  
Natural gas (MMBtu/d)
    26,504     $ 5.60  
/ MMBtu
    81%  
(a) - Hedged with fixed-price swaps.
                         
 
   
Year Ending
 
   
December 31, 2011
 
   
Volumes
Hedged
    Average Price  
Percentage
Hedged
 
NGLs (Bbl/d) (a)
    902     $ 1.34  
/ gallon
    13%  
Condensate (Bbl/d) (a)
    596     $ 2.12  
/ gallon
    26%  
Total (Bbl/d)
    1,498     $ 1.65  
/ gallon
    16%  
Natural gas (MMBtu/d)
    16,616     $ 6.29  
/ MMBtu
    43%  
(a) - Hedged with fixed-price swaps.
                         

Our Natural Gas Gathering and Processing segment’s commodity price risk related to physical sales of commodities is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2010, 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 $1.1 million;
·  
a $1.00 per barrel decrease in the price of crude oil would decrease annual net margin by approximately $1.1 million; and
·  
a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $1.2 million.

These estimates do not include any effects on demand for our services or changes in operations that we may undertake to compensate for or improve our ability to realize market advantages from periodic price changes.  For example, a change in the gross processing spread may cause us to change the amount of ethane we extract from the natural gas stream, impacting gathering and processing margins for certain contracts.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment primarily owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for non-processed gas.  We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended.

Our interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico.  Our interstate pipeline companies include:
·  
Midwestern Gas Transmission, which is a bi-directional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines near Joliet, Illinois;
·  
Viking Gas Transmission, which transports natural gas from an interconnection with a TransCanada Corporation pipeline 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 interconnections 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 to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north.

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

Our transportation contracts for our regulated natural gas activities are based upon rates stated in our tariffs.  Tariffs specify the maximum rates that customers can be charged, which can be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established at FERC or appropriate state jurisdictional agency proceedings, known as rate cases.  In Texas and Kansas, natural gas storage service is a fee business that may be regulated by the state in which the facility operates and by the FERC for certain types of services.  In Oklahoma, natural gas gathering and natural gas storage operations are also a fee business but are not subject to rate regulation by the OCC and have market-based rate authority from the FERC for certain types of services.

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:
 
   
Three Months Ended
   
Variances
 
   
March 31,
   
2010 vs. 2009
 
Financial Results
 
2010
   
2009
   
Increase (Decrease)
 
 
(Millions of dollars)
 
Transportation revenues
  $ 65.9     $ 56.6     $ 9.3       16 %
Storage revenues
    16.7       14.3       2.4       17 %
Gas sales and other revenues
    5.0       3.9       1.1       28 %
Cost of sales
    9.0       9.2       (0.2 )