-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, T+rWRGRpd4NsNEK4Xlgv+VfLaNGC6VePr3Yb9TvsfJ+q9X+UCn19c+kDSoYRIw9t ucLthfn/PHGTEshu7iAA5Q== 0000909281-10-000064.txt : 20100429 0000909281-10-000064.hdr.sgml : 20100429 20100429122154 ACCESSION NUMBER: 0000909281-10-000064 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 20100429 FILED AS OF DATE: 20100429 DATE AS OF CHANGE: 20100429 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ONEOK Partners LP CENTRAL INDEX KEY: 0000909281 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 931120873 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12202 FILM NUMBER: 10779983 BUSINESS ADDRESS: STREET 1: 100 WEST FIFTH STREET CITY: TULSA STATE: OK ZIP: 74103 BUSINESS PHONE: 9185887000 MAIL ADDRESS: STREET 1: 100 WEST FIFTH STREET CITY: TULSA STATE: OK ZIP: 74103 FORMER COMPANY: FORMER CONFORMED NAME: NORTHERN BORDER PARTNERS LP DATE OF NAME CHANGE: 19930719 10-Q 1 form_10-q.htm FORM 10-Q form_10-q.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 re asonable 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 Quarter ly 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 u tilize 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 uti lize 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 servic es 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 Pa rtnership 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 interruption s 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 acc ount 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 own s 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 allo cated 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 additiona l $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 d elivered 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 N GL 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 ser vices.

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 )     (2 %)
Net margin
    78.6       65.6       13.0       20 %
Operating costs
    22.8       20.2       2.6       13 %
Depreciation and amortization
    10.9       12.8       (1.9 )     (15 %)
Operating income
  $ 44.9     $ 32.6     $ 12.3       38 %
                                 
Equity earnings from investments
  $ 15.1     $ 16.2     $ (1.1 )     (7 %)
Allowance for equity funds used
     during construction
  $ -     $ 1.2     $ (1.2 )     (100 %)
Capital expenditures
  $ 3.2     $ 17.4     $ (14.2 )     (82 %)
 
   
Three Months Ended
 
   
March 31,
 
Operating Information (a)
 
2010
   
2009
 
Natural gas transportation capacity contracted (MMcf/d)
    5,860       5,247  
Transportation capacity subscribed
    91%       79%  
Average natural gas price
               
Mid-Continent region  ($/MMBtu)
  $ 5.03     $ 3.19  
(a) - Includes volumes for consolidated entities only.
               
 


 
Net margin increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of the following:
·  
an increase of $9.2 million from higher natural gas transportation margins, excluding retained fuel, primarily as a result of incremental margin from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission as a result of a new interconnection with the Rockies Express Pipeline that was placed in service beginning in June 2009; and
·  
an increase of $2.5 million from higher natural gas storage margins, excluding retained fuel, primarily as a result of contract renegotiations.

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

Equity earnings from investments decreased for the three months ended March 31, 2010, compared with the same period last year, due to lower subscription volumes and rates on Northern Border Pipeline.   

Allowance for equity funds used during construction and capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the Guardian Pipeline expansion and extension that was completed in February 2009. 

Natural Gas Liquids

Overview - Our natural gas liquids assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas.  We own FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.  We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois.  The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from unpro cessed natural gas, are connected to our gathering systems.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline.  Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline-quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content.  The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products.  These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, refineries and propane dis tributors.  We also purchase NGLs from third parties, as well as from our Natural Gas Gathering and Processing segment.

Revenues for our Natural Gas Liquids segment are derived primarily from exchange services, optimization and marketing, pipeline transportation, isomerization and storage, defined as follows:
·  
Our exchange services business primarily collects fees to gather, fractionate and treat unfractionated NGLs, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location.
·  
Our optimization and marketing 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 pipeline transportation business transports NGLs, NGL products and refined petroleum products primarily under our FERC-regulated tariffs.  Tariffs specify the rates we charge our customers and the general terms and conditions for NGL transportation service on our pipelines.
·  
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.



 
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids 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
  $ 1,770.2     $ 893.8     $ 876.4       98 %
Exchange service and storage revenues
    105.1       84.9       20.2       24 %
Transportation revenues
    27.2       22.3       4.9       22 %
Cost of sales and fuel
    1,798.5       898.4       900.1          *
Net margin
    104.0       102.6       1.4       1 %
Operating costs
    41.0       37.6       3.4       9 %
Depreciation and amortization
    18.3       12.7       5.6       44 %
Loss on sale of assets
    (0.8 )     -       (0.8 )     (100 %)
Operating income
  $ 43.9     $ 52.3     $ (8.4 )     (16 %)
                                 
Equity earnings from investments
  $ 0.4     $ 0.5     $ (0.1 )     (20 %)
Allowance for equity funds used
                               
during construction
  $ 0.2     $ 7.8     $ (7.6 )     (97 %)
Capital expenditures
  $ 15.8     $ 146.2     $ (130.4 )     (89 %)
* Percentage change is greater than 100 percent.
                         
 
 
Three Months Ended
 
 
March 31,
 
Operating Information
 
2010
   
2009
 
NGL sales (MBbl/d)
    427       380  
NGLs fractionated (MBbl/d)
    492       465  
NGLs transported-gathering lines (MBbl/d)
    441       324  
NGLs transported-distribution lines (MBbl/d)
    467       445  
Conway-to-Mont Belvieu OPIS average price differential
               
  Ethane ($/gallon)
  $ 0.08     $ 0.08  

Net margin increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of the following:
·  
an increase of $20.0 million due to increased volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new supply connections; and
·  
an increase of $3.0 million due to higher storage margins as a result of contract renegotiations; offset partially by,
·  
a decrease of $14.8 million related to lower optimization margins due to less NGL fractionation and transportation capacity available for optimization, offset partially by increased volumes marketed; and
·  
a decrease of $6.8 million due to the impact of operational measurement gains and losses as compared with the same period last year.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the operation of the Arbuckle Pipeline, increased materials and supplies expense 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 the Arbuckle Pipeline placed in service in August 2009, the Piceance lateral placed in service in October 2009 and the D-J Basin lateral placed in service in March 2009.

Allowance for equity funds used during construction and capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.


 
 
Contingencies

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.  Additional information about our legal proceedings is included under Part II, Item 1, Legal Proceedings, of this Quarterly Report and under Part I, Item 3, Legal Proceedings, in our Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets.  We have relied primarily on operating cash flow, bank credit facilities, debt issuances and the sale of common units for our liquidity and capital resources requirements.  We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flow.  We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis.  We have no guarantees of debt or other similar commitments to unaffiliated parties.

In the first quarter of 2010, we utilized our Partnership Credit Agreement to fund our short-term liquidity needs, and we have been able to access the public debt and equity markets for our long-term financing needs.  In February 2010, we issued common units.  See discussion below under “Equity Issuance” for more information.

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.  Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition and credit ratings, and market conditions.  We anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, as well as capital expenditures.

Capital Structure - The following table sets forth our capitalization structure for the periods indicated:
 
   
March 31,
   December 31,  
   
2010
 
2009
 
Long-term debt
 
48%
 
51%
 
Equity
 
52%
 
49%
 
           
Debt (including notes payable)
 
51%
 
55%
 
Equity
 
49%
 
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 pursuant to FERC regulations or our operating agreements.  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 Partnership Credit Agreement.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $1.5 billion.  At March 31, 2010, we had $310 million of borrowings outstanding under our Partnership Credit Agreement, which expires in March 2012, and approximately $5.4 million of available cash and cash equivalents.  As of March 31, 2010, our borrowing capacity was limited to $558 million of additional short- and long-term debt under the most restrictive provisions contained in our Partnership Credit Agreement.  At March 31, 2010, we had a total of $24.2 million in letters of credit issued outside of our Partnership Credit Agreement.
 
 

 
Our Partnership Credit Agreement contains certain financial, operational and legal covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report.  Among other things, these covenants 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.  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.
 
We expect to refinance our $250 million senior notes due June 15, 2010, with our Partnership Credit Agreement.
 
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 the sale and leaseback of facilities.

We are subject to changes in the debt and equity markets, and there is no assurance we will be able or willing to access the public or private markets in the future.  We may choose to meet our cash requirements by utilizing some combination of cash flows from operations, borrowing under existing credit facilities, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives.  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 maint ain our investment-grade credit ratings.
 
Our $250 million and $225 million senior notes, due June 15, 2010, and March 15, 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; however, once the $250 million 2010 senior notes have been retired, whether by maturity, redemption or otherwise, we will no longer have any obligation to offer to repurchase the $225 million 2011 senior notes in the event our credit rating falls below investment grade.  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 governi ng our senior notes due 2012, 2016, 2019, 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 events 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, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.

We may redeem the notes due 2012, 2016, 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, 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 respective note plus accrued and unpaid interest to the redemption date.  The notes due 2012, 2016, 2019, 2036 and 2037 are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of any non-guarantor subsidiaries.  Our long-term debt is nonrecourse to our general partner.
 
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.< /div>
 
Capital Expenditures - Our capital expenditures are typically financed through operating cash flows, short- and long-term debt and the issuance of equity.  Capital expenditures were $35.8 million and $192.5 million for the three months ended March 31, 2010 and 2009, respectively.  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.  Projected 2010 capital expenditures are significantly lower than 2009 capital expenditures due to various projects being completed or placed in service during 2009.



 
The following table summarizes our 2010 projected growth and maintenance capital expenditures, excluding AFUDC:
 
2010 Projected Capital Expenditures
 
Growth
   
Maintenance
   
Total
 
   
(Millions of dollars)
 
Natural Gas Gathering and Processing
  $ 240     $ 22     $ 262  
Natural Gas Pipelines
    3       22       25  
Natural Gas Liquids
    35       38       73  
Other
    -       2       2  
Total projected capital expenditures
  $ 278     $ 84     $ 362  

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.

Credit Ratings - Our credit ratings as of March 31, 2010, are shown in the table below:
 
Rating Agency
 
Rating
 
Outlook
Moody’s
 
Baa2
 
Stable
S&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 currently 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 but could trigger repurchase obligations with respect to certain of our long-term debt.  See additional discussion about our credit ratings un der “Long-term Financing.”

If our repurchase obligations are triggered, 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, seek alternative financing sources or sell assets 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.

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

Other than the note repurchase obligations described under “Long-term Financing” or the provisions discussed in the previous paragraph, 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.

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:

   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
   
(Millions of dollars)
Common unitholders
  $ 65.9     $ 58.8  
Class B unitholders
    40.1       39.4  
General partner
    26.0       22.7  
Total cash distributions paid before noncontrolling interests
  $ 132.0     $ 120.9  

In the three months ended March 31, 2010 and 2009, cash distributions paid to our general partner 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.

Additional information, about our cash distribution is included in “Cash Distribution Policy” under Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, in our Annual Report.

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 and natural gas 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 Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financ ial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.
 
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 or loss on sale of assets, deferred income taxes, equity earnings from investments, distributions received from unconsolidated affiliates, and changes in our assets and liabilities not classified as investing or financing activities.

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

   
Three Months Ended
   
Variances
 
   
March 31,
   
2010 vs. 2009
 
   
2010
   
2009
   
Increase (Decrease)
 
 
(Millions of dollars)
 
Total cash provided by (used in):
                       
Operating activities
  $ 55.5     $ 74.7     $ (19.2 )     (26 %)
Investing activities
    (34.4 )     (188.0 )     153.6       82 %
Financing activities
    (18.9 )     (63.2 )     44.3       (70 %)
Change in cash and cash equivalents
    2.2       (176.5 )     178.7          *
Cash and cash equivalents at beginning of period
    3.2       177.6       (174.4 )     (98 %)
Cash and cash equivalents at end of period
  $ 5.4     $ 1.1     $ 4.3          *
* Percentage change is greater than 100 percent.
                               
 
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities.  We provide services for producers and consumers of natural gas, condensate and NGLs.  Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.
 
 

 
Cash flows from operating activities, before changes in operating assets and liabilities, were $130.6 million for the three months ended March 31, 2010, compared with $135.5 million for the same period in 2009.  The decrease was due primarily to lower optimization margins in our Natural Gas Liquids segment, increased operating costs due to the operation of our recently completed capital projects and higher employee-related costs.

The changes in operating assets and liabilities decreased operating cash flows $75.1 million for the three months ended March 31, 2010, compared with a decrease of $60.8 million for the same period in 2009, primarily as a result of the following:
·  
the impact of commodity prices on our operating assets and liabilities;
·  
the changes in volumes of commodities in storage; and
·  
the timing of cash receipts from our revenues resulting in decreased accounts receivable; offset partially by
·  
the timing of payments for purchases of commodities and other expenses resulting in decreased accounts payable.
 
Investing Cash Flows - Cash used in investing activities decreased for the three months ended March 31, 2010, compared with the same period in 2009, due primarily to reduced capital expenditures as a result of the completion of our capital projects included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Projects,” in our Annual Report.

Financing Cash Flows - 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. 

In March 2009, we completed an underwritten public offering of senior notes totaling approximately $498.3 million, net of discounts but before offering expenses.  The net proceeds from the notes were used to repay borrowings under our Partnership Credit Agreement.

Cash distributions to our general and limited partners for the first quarter of 2010 were $132.1 million, compared with $120.9 million for the same period in 2009, an increase of $11.2 million.  This increase was due primarily to additional units outstanding during the first quarter of 2010, as well as cash distributions of $1.10 per unit paid during the first quarter of 2010, compared with cash distributions of $1.08 per unit paid during the first quarter of 2009.

Net repayments of notes payable were $213.0 million during the first quarter of 2010, compared with net repayments of $433.3 million for the first quarter of 2009.

ENVIRONMENTAL AND SAFETY MATTERS

Additional information about our environmental matters is included in Note G of the Notes to Consolidated Financial Statements in this Quarterly Report.

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas.  We are in compliance with all material requirements associated with the various pipeline safety regulations.  We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

Air and Water Emissions - The Clean Air Act, the 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.  We are in compliance with all material requiremen ts associated with the various air and water regulations.
 
 

 
The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane.  In addition, other federal, state and regional initiatives to regulate greenhouse gas emissions are under way.  We are monitoring federal and state legislation to assess the potential impact on our operations.  We estimate our direct greenhouse gas emissions annually as we collect all applicable greenhouse gas emission data for the previous year. Our most recent estimate indicates that our emissions are less than 4 million metric tons of carbon dioxide equivalents on an annual basis.  We expect to complete our annual estimate for 2009 during the second quarter of 2010 and will post the information on our W eb site when available.  We will continue efforts to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the EPA’s Mandatory Greenhouse Gas Reporting rule released in September 2009.  The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011 and will require us to track the emission equivalents for all NGLs delivered to our customers.  Also, the EPA has recently released a proposed subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities.  The new requirements are proposed to begin in January 2011, with the first reporting of fugitive emissions due March 31, 2012.  At this time, no legislation has been enacted as to what costs, fees or expense will be associated with any of these emissions.< /font>

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.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment.  These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility.  Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.
 
Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored.  We completed the Homeland Security assessments, and our facilities were subsequently assigned, on a preliminary basis, one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk.  To date, four of our facilities have been given a Tier 4 rating, and one other has been given a preliminary Tier 4 rating.  Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements.  We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - Homeland Security’s Transportation Security Administration, along with the United States Department of Transportation, has completed a review and inspection of our “critical facilities” and identified no material security issues.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment.  These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to new rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control; (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere, and (v) analyzing options for future energy investment.

We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.  Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.  We expect to complete our annual estimate for 2009 during the second quarter of 2010 and will post the information on our Web site when available.
 
 

 
FORWARD-LOOKING STATEMENTS
 
Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act.  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 Quarterly Report identified by 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.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Quarterly Report.  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 foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and 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 of 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 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 with 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;
·  
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 liquidity risks in U.S. credit markets;
·  
the impact of recently issued and future accounting updates 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 Part I, Item 1A, Risk Factors, in our Annual Report.  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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk in our Annual Report.

COMMODITY PRICE RISK

See Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.



 
CONTROLS AND PROCEDURES
 
Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, the Chief Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management of ONEOK Partners GP, including the officers of O NEOK Partners GP who are the equivalent of our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.  Based on their evaluation, they concluded that as of March 31, 2010, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports 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.

Changes in Internal Control Over Financial Reporting - We have made no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter ended March 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al.,  f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”) - As previously reported, ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants, are defendants in a lawsuit claiming underpayment of gas purchase proceeds.  The plaintiffs initially asserted that the defendants understated both the volume and the heating content of the purchased gas, and sought class certification for gas producers and royalty owners throughout the United States.  The Court refused to certify the class and the plaintiffs amended their petition to limit the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming, and limited the claim to undermeasurement of volume.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a 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 (“Boles II”) - As previously reported, 21 groups of defendants, including ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defendants in a lawsuit claiming underpayment of gas producers and royalty owners by allegedly understating the heating content of purchased gas in Kansas, Colorado and Wyoming.  This action was filed by the plaintiffs after the Court denied the initial motion for class status in Boles I, and Boles II was consolidated with Boles I to determine whether either or both cases may properly be certified.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.
 
RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report 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 discussion of risks and the other
 
 
 
 
information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

(REMOVED AND RESERVED)

Not Applicable.

OTHER INFORMATION

Not Applicable.

EXHIBITS

Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date.  All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC, and, other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.

The following exhibits are filed as part of this Quarterly Report:
 
Exhibit No.             Exhibit Description
 
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)).

 
101.INS
XBRL Instance Document.

 
101.SCH
XBRL Taxonomy Extension Schema Document.

 
101.CAL
XBRL Taxonomy Calculation Linkbase Document.

 
101.DEF
XBRL Taxonomy Extension Definitions Document.

 
101.LAB
XBRL Taxonomy Label Linkbase Document.

 
101.PRE
XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2010 and 2009; (iii) Consolidated Balance Sheets at March 31, 2010 and December 31, 2009; (iv) Consolidated Statements of Cash Flows for the three months
 
 
 
ended March 31, 2010 and 2009; (v) Consolidated Statement of Changes in Partners’ Equity for the three months ended March 31, 2010; (vi) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2010 and 2009; and (vii) Notes to Consolidated Financial Statements.

Users of this data are advised pursuant to Rule 401 of Regulation S-T that the information contained in the XBRL documents is unaudited, and these XBRL documents are not the official publicly filed consolidated financial statements of ONEOK Partners, L.P.  The purpose of submitting these XBRL formatted documents is to test the related format and technology, and, as a result, investors should continue to rely on the official filed version of the furnished documents and not rely on this information in making investment decisions.

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report 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.  We also make available on our Web site the Interactive Data Files voluntarily submitted as Exhibit 101 to this Quarterly Report.

 
 
 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 

     
ONEOK PARTNERS, L.P.
By:    ONEOK Partners GP, L.L.C., its General Partner
       
Date:
April 29, 2010
 
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)
 


42
EX-31.1 2 ex_31-1.htm SECTION 302 CERTIFICATION OF JOHN W. GIBSON ex_31-1.htm

Exhibit 31.1


Certification

I, John W. Gibson, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK Partners, L.P.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: April 29, 2010

/s/ John W. Gibson
John W. Gibson
Chief Executive Officer



 
EX-31.2 3 ex_31-2.htm SECTION 302 CERTIFICATION OF CURTIS L. DINAN ex_31-2.htm

Exhibit 31.2


Certification

I, Curtis L. Dinan, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK Partners, L.P.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: April 29, 2010

/s/ Curtis L. Dinan
Curtis L. Dinan
Chief Financial Officer


EX-32.1 4 ex_32-1.htm SECTION 906 CERTIFICATION OF JOHN W. GIBSON ex_32-1.htm
 
Exhibit 32.1
 
 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK Partners, L.P. (the “Company”) for the period ending March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. Gibson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ John W. Gibson
John W. Gibson
Chief Executive Officer

April 29, 2010


A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK Partners, L.P. and will be retained by ONEOK Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.2 5 ex_32-2.htm SECTION 906 CERTIFICATION OF CURTIS L. DINAN ex_32-2.htm
 
Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK Partners, L.P. (the “Company”) for the period ending March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Curtis L. Dinan, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Curtis L. Dinan
Curtis L. Dinan
Chief Financial Officer

April 29, 2010


A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK Partners, L.P. and will be retained by ONEOK Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.
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For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil prices.&#160;&#160;We validate our valuation inputs with third-party information and settlement prices from other sources, where available.&#160; 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 i nterest rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and U.S. Treasury swaps.&#160; Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed.&#160; 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.</font></div><div style="DISPLAY: block; 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Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Staff Accounting Bulletin (SAB) -Number Topic 6 -Section I -Subsection 7 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 109 -Paragraph 45 -Subparagraph b Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 109 -Paragraph 289 Reference 5: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 08 -Paragraph h -Article 4 false 9 2 us-gaap_IncomeLossFromEquityMethodInvestments us-gaap true credit duration monetary No definition available. false false false false false false false false false false true negated false 1 false true false false -21116000 -21116 false false false 2 false true false false -21222000 -21222 false false false This item represents the entity's proportionate share for the period of the net income (loss) of its investee (such as unconsolidated subsidiaries and joint ventures) to which the equity method of accounting is applied. Such amount typically reflects adjustments similar to those made in preparing consolidated statements, including adjustments to eliminate intercompany gains and losses, and to amortize, if appropriate, any difference between cost and underlying equity in net assets of the investee at the date of investment. 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This element excludes distributions that constitute a return of investment, which are classified as investing activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 03 -Paragraph 13 -Article 5 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Principles Board Opinion (APB) -Number 18 -Paragraph 19 false 11 2 us-gaap_IncreaseDecreaseInOperatingCapitalAbstract us-gaap true na duration string No definition available. false false false false false true false false false false false label false 1 false false false false 0 0 false false false 2 false false false false 0 0 false false false No definition available. false 12 3 us-gaap_IncreaseDecreaseInReceivables us-gaap true credit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false 172824000 172824 false false false 2 false true false false 11224000 11224 false false false The net change during the reporting period in the total amount due within one year (or one operating cycle) from all parties, associated with underlying transactions that are classified as operating activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 13 3 us-gaap_IncreaseDecreaseInDueFromAffiliatesCurrent us-gaap true credit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false -1538000 -1538 false false false 2 false true false false 4880000 4880 false false false The net change during the reporting period in current receivables (due within one year or one operating cycle) to be collected from an entity that is controlling, under the control of, or within the same control group as the reporting entity by means of direct or indirect ownership. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 14 3 us-gaap_IncreaseDecreaseInInventories us-gaap true credit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false -1764000 -1764 false false false 2 false true false false 44641000 44641 false false false The net change during the reporting period in the aggregate value of all inventory held by the reporting entity, associated with underlying transactions that are classified as operating activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 15 3 us-gaap_IncreaseDecreaseInAccountsPayableTrade us-gaap true debit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false -168406000 -168406 false false false 2 false true false false -65065000 -65065 false false false Change in recurring obligations of a business that arise from the acquisition of merchandise, materials, supplies and services used in the production and sale of goods and services. 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Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 17 3 oks_CommodityExchangesAndImbalancesNet oks false debit duration monetary The net change during the reporting period in the asset (liability) created by natural gas imbalances and NGL exchange... false false false false false false false false false false false terselabel false 1 false true false false -56558000 -56558 false false false 2 false true false false -59078000 -59078 false false false The net change during the reporting period in the asset (liability) created by natural gas imbalances and NGL exchange agreements that are valued at market or their contractually stipulated rate. No authoritative reference available. false 18 3 us-gaap_IncreaseDecreaseInInterestPayableNet us-gaap true debit duration monetary No definition available. false false false false false false false false false false false label false 1 false true false false 23045000 23045 false false false 2 false true false false 33555000 33555 false false false The net change during the reporting period in interest payable, which represents the amount owed to note holders, bond holders, and other parties for interest earned on loans or credit extended to the reporting entity. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 19 3 us-gaap_IncreaseDecreaseInOtherOperatingCapitalNet us-gaap true credit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false -37792000 -37792 false false false 2 false true false false -25974000 -25974 false false false For entities with classified balance sheets, the net change during the reporting period in the value of other assets or liabilities used in operating activities, that are not otherwise defined in the taxonomy. For entities with unclassified balance sheets, the net change during the reporting period in the value of all other assets or liabilities used in operating activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 false 20 3 us-gaap_NetCashProvidedByUsedInOperatingActivities us-gaap true na duration monetary No definition available. false false false false false false false false false false false totallabel false 1 false true false false 55479000 55479 false false false 2 false true false false 74776000 74776 false false false The net cash from (used in) all of the entity's operating activities, including those of discontinued operations, of the reporting entity. Operating activities generally involve producing and delivering goods and providing services. Operating activity cash flows include transactions, adjustments, and changes in value that are not defined as investing or financing activities. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 28 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 26 true 21 1 us-gaap_NetCashProvidedByUsedInInvestingActivitiesContinuingOperationsAbstract us-gaap true na duration string No definition available. false false false false false true false false false false false false 1 false false false false 0 0 false false false 2 false false false false 0 0 false false false Cash generated by or used in investing activities of continuing operations; excludes cash flows from discontinued operations. false 22 2 oks_ChangesInInvestmentsInUnconsolidatedAffiliates oks false debit duration monetary The net cash inflow (outflow) associated with distributions received from unconsolidated affiliates that constitute a return... false false false false false false false false false false false false 1 false true false false 1334000 1334 false false false 2 false true false false 3362000 3362 false false false The net cash inflow (outflow) associated with distributions received from unconsolidated affiliates that constitute a return of investment net of investments in or advances to unconsolidated affiliates. Unconsolidated affiliates are investments in joint ventures and entities in which the entity has an equity ownership interest. No authoritative reference available. false 23 2 us-gaap_PaymentsToAcquirePropertyPlantAndEquipment us-gaap true credit duration monetary No definition available. false false false false false false false false false false true negated false 1 false true false false -35827000 -35827 false false false 2 false true false false -192494000 -192494 false false false The cash outflow associated with the acquisition of long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale; includes cash outflows to pay for construction of self-constructed assets. 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Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 18 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 20 -Subparagraph b false 31 2 us-gaap_ProceedsFromIssuanceOfLongTermDebt us-gaap true debit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false 0 0 false false false 2 false true false false 498325000 498325 false false false The cash inflow from a debt initially having maturity due after one year or beyond the operating cycle, if longer. 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Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 18 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 20 -Subparagraph b false 34 2 us-gaap_ProceedsFromIssuanceOfCommonLimitedPartnersUnits us-gaap true debit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false 322721000 322721 false false false 2 false true false false 0 0 false false false The cash inflow from the issuance of common limited partners units during the period. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 18 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 19 -Subparagraph a false 35 2 us-gaap_ProceedsFromOtherEquity us-gaap true debit duration monetary No definition available. false false false false false false false false false false false false 1 false true false false 6820000 6820 false false false 2 false true false false 0 0 false false false The cash inflow from other equity not otherwise defined in the taxonomy. 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Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 26 true 37 1 us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease us-gaap true na duration monetary No definition available. false false false false false false false false false false false totallabel false 1 false true false false 2228000 2228 false false false 2 false true false false -176506000 -176506 false false false The net change between the beginning and ending balance of cash and cash equivalents. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 26 true 38 1 us-gaap_CashAndCashEquivalentsAtCarryingValue us-gaap true debit instant monetary No definition available. false false false false false false false false true false false periodstartlabel false 1 false true false false 3151000 3151 false false false 2 false true false false 177635000 177635 false false false Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased th ree years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits should not be reported as cash and cash equivalents. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 7, 26 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 8, 9 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 7 -Footnote 1 Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 02 -Paragraph 1 -Article 5 false 39 1 us-gaap_CashAndCashEquivalentsAtCarryingValue us-gaap true debit instant monetary No definition available. false false false false false false false false false true false periodendlabel false 1 true true false false 5379000 5379 false false false 2 true true false false 1129000 1129 false false false Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased th ree years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits should not be reported as cash and cash equivalents. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 7, 26 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 8, 9 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 95 -Paragraph 7 -Footnote 1 Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 02 -Paragraph 1 -Article 5 false false 2 37 false Thousands UnKnown UnKnown false true XML 22 R16.xml IDEA: LIMITED PARTNERS' NET INCOME PER UNIT 2.0.0.10 false LIMITED PARTNERS' NET INCOME PER UNIT 006100 - Disclosure - LIMITED PARTNERS' NET INCOME PER UNIT true false false false 1 usd $ false false u000 Standard http://www.xbrl.org/2003/iso4217 USD iso4217 0 u001 Standard http://www.xbrl.org/2003/instance shares xbrli 0 u002 Divide http://www.xbrl.org/2003/iso4217 USD iso4217 http://www.xbrl.org/2003/instance shares xbrli 0 2 0 oks_NotesToFinancialStatementsAbstract oks false na duration string No definition available. false false false false false true false false false false false false 1 false false false false 0 0 false false false No definition available. false 3 1 oks_LimitedPartnersNetIncomePerUnitAndDistributionsToPartnersTextBlock oks false na duration string This element describes net income per unit, ownership structure, incentive distributions and distributions paid. false false false false false false false false false false false terselabel false 1 false false false false 0 0 <div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">J.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;LIMITED PARTNERS&#8217; NET INCOME PER UNIT</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Limited partners&#8217; net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner&#8217;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.&#160;&#16 0;ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B units.&#160;&#160;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.&#160;&#160;ONEOK retains the option to withdraw its waiver at any time by giving us no less than 90 days advance notice.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left">< font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">For purposes of our calculation of limited partners&#8217; 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&#8217;s incentive distribution rights based on the total cash distributions declared for the period.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The terms o f our Partnership Agreement limit the general partner&#8217;s incentive distribution to the amount of available cash calculated for the period.&#160;&#160;As such, incentive distribution rights are not allocated on undistributed earnings or distributions in excess of earnings.&#160;&#160;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 </font><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">distribution rights would not apply.&#160;&#160;For additional information regarding our general partner&#8217;s incentive distribution rights, see Note J of the Notes to Consolidated Financial Statements in our Annual Report.</font></div> J.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;LIMITED PARTNERS&#8217; NET INCOME PER UNITLimited partners&#8217; 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(OES), a subsidiary of ONEOK.&#160;&#160;OES enters into similar commodity derivative contracts with third parties at our direction and on our behalf.&#160;&#160;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.&#160;&#160;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.&#160;&#160;At December 31, 2009, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty.</font></div> C.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVESRisk Management Activities - We are false false false This element can be used to disclose the entity's entire derivative instruments and hedging activities disclosure as a single block of text. 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Partners include general, limited and preferred partners. Limited liability partnerships (LLPs) are formed in accordance with the laws of the state in which such entities are organized. Because those laws are not uniform, the characteristics of LPCs vary from state to state. However, LLPs generally have the following characteristics: An LLP is an unincorporated association of two or more "persons"; Its members have limited personal liability for the obligations or debts of the entity; It is classified as a partnership for federal income tax purposes. 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Units represent shares of ownership of the general, limited, and preferred partners of a publicly listed limited partnership or a master limited partnership. General partners have unlimited liability and manage the partnership. Limited partners have limited liability and do not manage the partnership. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Emerging Issues Task Force (EITF) -Number 87-21 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Practice Bulletin (PB) -Number 14 -Paragraph 15 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 04 -Paragraph 16 -Subparagraph a, b -Article 6 false false 6 10 false Thousands NoRounding UnKnown false true XML 26 defnref.xml IDEA: XBRL DOCUMENT Total obligations, excluding long-term debt, incurred as part of normal operations that is expected to be repaid beyond the following twelve months or one business cycle. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. 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The Class B limited partners are partners of a publicly traded limited partnership or master limited partnership. Limited partners have limited liability and do not manage the partnership. No authoritative reference available. No authoritative reference available. No authoritative reference available. Carrying amount as of the balance sheet date of the asset arising from natural gas pipeline imbalances or natural gas liquid exchange agreements valued at market or their contractually stipulated rate. Natural gas imbalances and natural gas liquid exchange agreements are settled in cash or made up in kind within one year, according to the terms of the respective pipeline tariff or by exchange agreement. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. 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No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The net cash inflow (outflow) associated with distributions received from unconsolidated affiliates that constitute a return of investment net of investments in or advances to unconsolidated affiliates. Unconsolidated affiliates are investments in joint ventures and entities in which the entity has an equity ownership interest. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The cash outflow from the entity's earnings to the unitholders and general partner. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Sum of operating profit and nonoperating income (expense) before income taxes, extraordinary items, cumulative effects of changes in accounting principles and noncontrolling interest. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. This element describes net income per unit, ownership structure, incentive distributions and distributions paid. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The net change during the reporting period in the asset (liability) created by natural gas imbalances and NGL exchange agreements that are valued at market or their contractually stipulated rate. No authoritative reference available. No authoritative reference available. No authoritative reference available. General taxes including primarily payroll and ad valorem. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The cost of equity related to financing the construction of regulated assets. No authoritative reference available. Expenses incurred for the administration, supervision, operation, maintenance, preservation, and protection of the entity's business. No authoritative reference available. No authoritative reference available. No authoritative reference available. The Class B limited partner's ownership share in the capital account balance. The Class B limited partners are partners of a publicly traded limited partnership or master limited partnership. Limited partners have limited liability and do not manage the partnership. No authoritative reference available. Total contribution made by general partner during the reporting period. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The number of Class B limited partner units outstanding. The Class B limited partners are partners of a publicly traded limited partnership or master limited partnership. Limited partners have limited liability and do not manage the partnership. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The cost of equity related to financing the construction of regulated assets. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Sum of the carrying amounts as of the balance sheet date of all assets, excluding property, plant and equipment, that are expected to be realized in cash, sold or consumed after one year or beyond the normal operating cycle, if longer. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Carrying amount as of the balance sheet date of the liability arising from natural gas pipeline imbalances or natural gas liquid exchange agreements valued at market or their contractually stipulated rate. Natural gas imbalances and natural gas liquid exchange agreements are settled in cash or made up in kind within one year, according to the terms of the respective pipeline tariff or by exchange agreement. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Carrying amount as of the balance sheet date, which is the cumulative amount paid, adjusted for any amortization recognized prior to adoption of FAS 142 and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions and the sum of the carrying amounts of all intangible assets as of the balance date, net of accumulated amortization and impairment charges. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. XML 27 R13.xml IDEA: COMMITMENTS AND CONTINGENCIES 2.0.0.10 false COMMITMENTS AND CONTINGENCIES 006070 - Disclosure - COMMITMENTS AND CONTINGENCIES true false false false 1 usd $ false false u000 Standard http://www.xbrl.org/2003/iso4217 USD iso4217 0 u001 Standard http://www.xbrl.org/2003/instance shares xbrli 0 u002 Divide http://www.xbrl.org/2003/iso4217 USD iso4217 http://www.xbrl.org/2003/instance shares xbrli 0 2 0 oks_NotesToFinancialStatementsAbstract oks false na duration string No definition available. false false false false false true false false false false false false 1 false false false false 0 0 false false false No definition available. false 3 1 us-gaap_CommitmentsAndContingenciesDisclosureTextBlock us-gaap true na duration string No definition available. false false false false false false false false false false false terselabel false 1 false false false false 0 0 <div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">G.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;COMMITMENTS AND CONTINGENCIES</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-WEIGHT: bold">Environmental Liabilities </font>-<font style="DISPLAY: inline; FONT-WEIGHT: bold">&#160;</font>We are subject to multiple environmental, historical and wildlife preservation laws and regulations affecting many aspects of our present and future operations.&#160;&#160;Regulated ac tivities 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.&#160;&#160;These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals.&#160;&#160;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.&#160;&#160;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.&#160;&#160;In addition, emission controls r equired under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities.&#160;&#160;We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">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 expendi tures related to environmental matters had no material effect upon earnings or cash flows during the three months ended March 31, 2010 or 2009.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The EPA is proposing to finalize the &#8220;Tailoring Rule&#8221; that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.&#160;&#160;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.&#160; The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.&#160;&#160;At this time, potential costs, fees or expenses associated with the proposed &#8220;Tailoring Rule&#8221; are unknown.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">In addition, the EPA has issued a proposed rule on air-quality standards, &#8220;National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,&#8221; also known as RICE NESHAP, scheduled to be adopted in early 2013.&#160;&#160;The proposed rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment.&#160;&#160;We do not expect these expenditures to have a material impact on our results of operations, financial positio n or cash flows.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-WEIGHT: bold">Legal Proceedings</font> - We are a party to various litigation matters and claims that have arisen in the normal course of our operations.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMI LY: Times New Roman"><font style="DISPLAY: inline; FONT-WEIGHT: bold">Overland Pass Pipeline Company</font> - Overland Pass Pipeline Company is a joint venture between us and a subsidiary of The Williams Companies, Inc. (Williams).&#160;&#160;We own 99 percent of the joint venture and operate the pipeline.&#160;&#160;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&#8217;s operating agreement.&#160;&#160;If Williams exercises its option to increase its ownership to 50 percent, Williams would have the option to become operator.&#160;&#160;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.</font></div> G.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;COMMITMENTS AND CONTINGENCIESEnvironmental Liabilities -&#160;We are subject to multiple false false false Includes disclosure of commitments and contingencies. 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Disclosure - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES true false false false 1 usd $ false false u000 Standard http://www.xbrl.org/2003/iso4217 USD iso4217 0 u001 Standard http://www.xbrl.org/2003/instance shares xbrli 0 u002 Divide http://www.xbrl.org/2003/iso4217 USD iso4217 http://www.xbrl.org/2003/instance shares xbrli 0 2 0 oks_NotesToFinancialStatementsAbstract oks false na duration string No definition available. false false false false false true false false false false false false 1 false false false false 0 0 false false false No definition available. false 3 1 us-gaap_SignificantAccountingPoliciesTextBlock us-gaap true na duration string No definition available. false false false false false false false false false false false label false 1 false false false false 0 0 <div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">A.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">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.&#160;&#160;All such adjustments are of a normal recurring nature.&#160;&#160;The 2009 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.&#160;&#160;These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Recently Issued Accounting Updates</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The following recently issued accounting standards updates affect our consolidated financial statements and related disclosures:</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-WEIGHT: bold">Fair Value Measurements and Disclosures</font> - In January 2010, the FASB issued ASU 2010-06, &#8220;Improving Disclosures about Fair Value Measurements,&#8221; which established new disclosure requirement s and clarified existing requirements for disclosures of fair value measurements.&#160;&#160;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.&#160;&#160;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.&#160;&#160;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.&#160;&#160;ASU 2010-06 requires prospective application in the period of adoption, and we have not recast our prior-year disclosures.&#160;&#160;See Note B for more discussion o f our fair value measurements.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-WEIGHT: bold">Embedded Credit Derivatives</font> - In March 2010, the FASB issued ASU 2010-11, &#8220;Scope Exception Related to Embedded Credit Derivatives,&#8221; which clarified that disclosures required for credit derivatives do not apply to an embedded derivative&#8217;s feature related to the transfer of credit risk that is only in the form of subordination of one financial instrument to another.&#160;&#160;This guidance will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.&#160;&#160;We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial st atements and related disclosures.</font></div> A.&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;&#160;SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESOur accompanying unaudited consolidated financial false false false This element may be used to describe all significant accounting policies of the reporting entity. 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