Attached files

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EX-32.2 - EXHIBIT 32.2 (SECTION 906 CERTIFICATION OF ROBERT F. MARTINOVICH) - ONEOK Partners LPexhibit_32-2.htm
EX-31.2 - EXHIBIT 31.2 (SECTION 302 CERTIFICATION OF ROBERT F. MARTINOVICH) - ONEOK Partners LPexhibit_31-2.htm
EX-32.1 - EXHIBIT 32.1 (SECTION 906 CERTIFICATION OF JOHN W. GIBSON) - ONEOK Partners LPexhibit_32-1.htm
EX-31.1 - EXHIBIT 31.1 (SECTION 302 CERTIFICATION OF JOHN W. GIBSON) - ONEOK Partners LPexhibit_31-1.htm
EXCEL - IDEA: XBRL DOCUMENT - ONEOK Partners LPFinancial_Report.xls
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, 2011
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 X  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 28, 2011
Common units
Class B units    
 
65,413,677 units
36,494,126 units
 
 
 
 

ONEOK PARTNERS, L.P.
Part I.
Financial Information
 
Page No.
 
 
 
 
5
 
 
 
6
 
 
7
 
 
8-9
 
 
10
 
11-22
 
 
23-41
 
 
41
41-42
 
 
 
42
 
42
 
 
42
 
42
 
42
 
42
 
42-43
 
 
44
 
As used in this Quarterly Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.

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

INFORMATION AVAILABLE ON OUR WEBSITE

We make available on our website 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 website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.  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.
 
2

 

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, 2010
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
CFTC
Commodities Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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
Guardian Pipeline
Guardian Pipeline, L.L.C.
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary
   of ONEOK Partners, L.P.
KCC
LIBOR
MBbl
Kansas Corporation Commission
London Interbank Offered Rate
Thousand barrels
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
Midwestern Gas Transmission
Midwestern Gas Transmission Company
MMBbl
Million barrels
MMBtu
Million British thermal units
MMBtu/d
Million British thermal units per day
MMcf/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 Financial Services LLC
SEC
Securities and Exchange Commission
 
Securities Act
Securities Act of 1933, as amended
Viking Gas Transmission
Viking Gas Transmission Company
XBRL
eXtensible Business Reporting Language

         
ITEM 1.  FINANCIAL STATEMENTS
         
ONEOK Partners, L.P. and Subsidiaries
         
CONSOLIDATED STATEMENTS OF INCOME
         
   
Three Months Ended
 
   
March 31,
 
(Unaudited)
 
2011
 
2010
 
    (Thousands of dollars, except per unit amounts)
           
Revenues
  $ 2,499,610   $ 2,204,006  
Cost of sales and fuel
    2,170,056     1,942,881  
Net margin
    329,554     261,125  
Operating expenses
             
Operations and maintenance
    95,142     87,205  
Depreciation and amortization
    42,730     43,871  
General taxes
    13,601     9,101  
Total operating expenses
    151,473     140,177  
Loss on sale of assets
    (510 )   (786 )
Operating income
    177,571     120,162  
Equity earnings from investments (Note H)
    32,092     21,116  
Allowance for equity funds used during construction
    466     247  
Other income
    2,385     1,850  
Other expense
    (614 )   (342 )
Interest expense
    (57,268 )   (54,153 )
Income before income taxes
    154,632     88,880  
Income taxes
    (3,575 )   (4,860 )
Net income
    151,057     84,020  
Less: Net income attributable to noncontrolling interests
    147     152  
Net income attributable to ONEOK Partners, L.P.
  $ 150,910   $ 83,868  
               
Limited partners' interest in net income:
             
Net income attributable to ONEOK Partners, L.P.
  $ 150,910   $ 83,868  
General partner's interest in net income
    (32,642 )   (27,387 )
Limited partners' interest in net income
  $ 118,268   $ 56,481  
               
Limited partners' net income per unit, basic and diluted (Note G)
  $ 1.16   $ 0.57  
               
Number of units used in computation (thousands)
    101,908     99,721  
See accompanying Notes to Consolidated Financial Statements.
             

 

 
       
CONSOLIDATED BALANCE SHEETS
       
 
March 31,
 
December 31,
 
(Unaudited)
2011
 
2010
 
Assets
(Thousands of dollars)
 
Current assets
       
Cash and cash equivalents
$ 617,403   $ 898  
Accounts receivable, net
  759,246     815,141  
Affiliate receivables
  1,514     5,161  
Gas and natural gas liquids in storage
  232,219     317,159  
Commodity imbalances
  75,907     92,353  
Other current assets
  45,350     48,060  
Total current assets
  1,731,639     1,278,772  
             
Property, plant and equipment
           
Property, plant and equipment
  5,995,839     5,857,000  
Accumulated depreciation and amortization
  1,138,326     1,099,548  
Net property, plant and equipment
  4,857,513     4,757,452  
             
Investments and other assets
           
Investments in unconsolidated affiliates (Note H)
  1,186,588     1,188,124  
Goodwill and intangible assets
  659,287     661,204  
Other assets
  47,277     34,548  
Total investments and other assets
  1,893,152     1,883,876  
Total assets
$ 8,482,304   $ 7,920,100  
             
Liabilities and partners' equity
           
Current liabilities
           
Current maturities of long-term debt
$ 11,931   $ 236,931  
Notes payable (Note D)
  -     429,855  
Accounts payable
  810,487     852,330  
Affiliate payables
  25,921     29,765  
Commodity imbalances
  249,095     291,110  
Accrued interest
  77,716     49,606  
Other current liabilities
  85,827     84,545  
Total current liabilities
  1,260,977     1,974,142  
             
Long-term debt, excluding current maturities (Note E)
  3,873,234     2,581,572  
             
Deferred credits and other liabilities
  95,025     87,393  
             
Commitments and contingencies (Note J)
           
             
Equity
           
ONEOK Partners, L.P. partners’ equity:
           
General partner
  95,732     94,691  
Common units: 65,413,677 units issued and outstanding at
   March 31, 2011 and December 31, 2010
  1,826,864     1,825,521  
Class B units: 36,494,126 units issued and outstanding at
   March 31, 2011 and December 31, 2010
  1,346,072     1,345,322  
Accumulated other comprehensive income (loss)
  (20,728 )   6,283  
Total ONEOK Partners, L.P. partners' equity
  3,247,940     3,271,817  
             
Noncontrolling interests in consolidated subsidiaries
  5,128     5,176  
             
Total equity
  3,253,068     3,276,993  
Total liabilities and equity
$ 8,482,304   $ 7,920,100  
See accompanying Notes to Consolidated Financial Statements.
 

 
ONEOK Partners, L.P. and Subsidiaries
       
Three Months Ended
 
 
March 31,
 
(Unaudited)
2011
 
2010
 
 
(Thousands of dollars)
 
Operating activities
       
Net income
$ 151,057   $ 84,020  
Depreciation and amortization
  42,730     43,871  
Allowance for equity funds used during construction
  (466 )   (247 )
Loss on sale of assets
  510     786  
Deferred income taxes
  1,940     1,239  
Equity earnings from investments
  (32,092 )   (21,116 )
Distributions received from unconsolidated affiliates
  27,607     21,998  
Changes in assets and liabilities:
           
Accounts receivable
  55,895     172,824  
Affiliate receivables
  3,647     (1,538 )
Gas and natural gas liquids in storage
  84,940     (1,764 )
Accounts payable
  (36,141 )   (168,406 )
Affiliate payables
  (3,844 )   (4,883 )
Commodity imbalances, net
  (25,569 )   (56,558 )
Accrued interest
  28,110     23,045  
Other assets and liabilities
  (20,818 )   (37,792 )
Cash provided by operating activities
  277,506     55,479  
             
Investing activities
           
Capital expenditures (less allowance for equity funds used during construction)
  (144,826 )   (35,827 )
Contributions to unconsolidated affiliates
  (250 )   (197 )
Distributions received from unconsolidated affiliates
  4,904     1,531  
Proceeds from sale of assets
  516     138  
Cash used in investing activities
  (139,656 )   (34,355 )
             
Financing activities
           
Cash distributions:
           
General and limited partners
  (147,776 )   (132,086 )
Noncontrolling interests
  (195 )   (368 )
Borrowing (repayment) of notes payable, net
  (429,855 )   (213,000 )
Issuance of long-term debt, net of discounts
  1,295,450     -  
Long-term debt financing costs
  (10,986 )   -  
Repayment of long-term debt
  (227,983 )   (2,983 )
Issuance of common units, net of discounts
  -     322,721  
Contribution from general partner
  -     6,820  
Cash provided by (used in) financing activities
  478,655     (18,896 )
Change in cash and cash equivalents
  616,505     2,228  
Cash and cash equivalents at beginning of period
  898     3,151  
Cash and cash equivalents at end of period
$ 617,403   $ 5,379  
See accompanying Notes to Consolidated Financial Statements.
 



ONEOK Partners, L.P. and Subsidiaries
             
     
                 
                 
 
ONEOK Partners, L.P. Partners' Equity
 
                 
(Unaudited)
Common
Units
Class B
Units
General
Partner
Common
Units
 
(Units)
 
(Thousands of dollars)
 
                 
December 31, 2010
  65,413,677     36,494,126   $ 94,691   $ 1,825,521  
Net income
  -     -     32,642     75,915  
Other comprehensive income
  -     -     -     -  
Distributions paid (Note F)
  -     -     (31,601 )   (74,572 )
March 31, 2011
  65,413,677     36,494,126   $ 95,732   $ 1,826,864  
See accompanying Notes to Consolidated Financial Statements.
       



ONEOK Partners, L.P. and Subsidiaries
             
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
     
(Continued)
               
   
ONEOK Partners, L.P. Partners' Equity
         
(Unaudited)  
Class B
Units
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total Equity
 
 
(Thousands of dollars)
 
                 
December 31, 2010
$ 1,345,322   $ 6,283   $ 5,176   $ 3,276,993  
Net income
  42,353     -     147     151,057  
Other comprehensive income
  -     (27,011 )   -     (27,011 )
Distributions paid (Note F)
  (41,603 )   -     (195 )   (147,971 )
March 31, 2011
$ 1,346,072   $ (20,728 ) $ 5,128   $ 3,253,068  
                         

 
ONEOK Partners, L.P. and Subsidiaries
       
       
         
 
Three Months Ended
 
 
March 31,
 
(Unaudited)
2011
 
2010
 
 
(Thousands of dollars)
 
         
Net income
$ 151,057   $ 84,020  
Other comprehensive income (loss)
           
Unrealized gains (losses) on derivatives
  (25,753 )   24,707  
Less:  Realized gains (losses) on derivatives
   recognized in net income
  1,258     (4,648 )
Total other comprehensive income (loss)
  (27,011 )   29,355  
Comprehensive income
  124,046     113,375  
Less: Comprehensive income attributable to noncontrolling interests
  147     152  
Comprehensive income attributable to ONEOK Partners, L.P.
$ 123,899   $ 113,223  
See accompanying Notes to Consolidated Financial Statements.
           

ONEOK Partners, L.P. and Subsidiaries
(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 2010 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.  We have reclassified certain prior-period amounts to conform to current-period classifications.

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

Recently Issued Accounting Standards Update - In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which requires separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements.  We adopted this guidance with this Quarterly Report, and the impact was not material.  Other provisions of ASU 2010-06 were adopted in 2010.  See Note B for more discussion of our fair value measurements.

B.           FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date.  We use the income approach to determine the fair value of our derivative assets and liabilities and consider the markets in which the transactions are executed.  While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive.  This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values.  For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil prices.  We validate our valuation inputs with third-party information and settlement prices from other sources, where available.  In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using the interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate 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, 2011
 
                         
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
 
(Thousands of dollars)
 
Derivatives - commodity
                       
Assets
$ -   $ 11,572   $ 2,589   $ 14,161   $ (12,520 ) $ 1,641  
Liabilities
$ -   $ (16,823 ) $ (13,285 ) $ (30,108 ) $ 12,520   $ (17,588 )
                                     
 
December 31, 2010
 
                         
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
 
(Thousands of dollars)
 
Derivatives - commodity
                                   
Assets
$ -   $ 15,305   $ 2,311   $ 17,616   $ (6,516 ) $ 11,100  
Liabilities
$ -   $ (5,361 ) $ (1,155 ) $ (6,516 ) $ 6,516   $ -  
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets 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, or other current liabilities and other liabilities in our Consolidated Balance Sheets.
       
 
At March 31, 2011, and December 31, 2010, we had no cash collateral held or posted under our mater-netting arrangements.
 
Derivative instruments categorized as Level 1 normally would include exchange-traded contracts that are valued using unadjusted quoted prices in active markets.

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 NGL products, natural gas basis swaps and certain physical forward contracts for NGL products.  These instruments 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 natural gas 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.

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)
2011
 
2010
 
 
(Thousands of dollars)
 
Net assets (liabilities) at beginning of period
$ 1,156   $ (13,052 )
   Total realized/unrealized gains (losses):
           
       Included in earnings (a)
  172     -  
       Included in other comprehensive income (loss)
  (12,024 )   10,720  
Net liabilities at end of period
$ (10,696 ) $ (2,332 )
             
Total gains for the period included in earnings
           
attributable to the change in unrealized gains (losses)
           
relating to assets and liabilities still held as of the end
           
of the period (a)
$ 808   $ -  
(a) - Included in revenues in our Consolidated Statements of Income.
       


 
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items.
 
The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $4.2 billion and $3.1 billion at March 31, 2011, and December 31, 2010, respectively.  The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.9 billion and $2.8 billion at March 31, 2011, and December 31, 2010, respectively.  The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for our senior notes or 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 physical 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 contracts.  We are also exposed to basis risk between the various production and market locations where we buy and sell commodities.  As part of our hedging strategy, we use the previously described commodity derivative instruments to minimize the impact of price fluctuations related to natural gas, NGLs and condensate.  We reduce our gross processing spread exposure through a combination of physical and financial hedges.  We utilize a portion of our POP equity natural gas production 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 retain 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, 2011, and December 31, 2010, there were no 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 physical forward contracts to reduce the impact of price fluctuations related to NGLs.  At March 31, 2011, and December 31, 2010, there were no financial derivative instruments with respect to our NGL operations.

 
 
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, 2011, and December 31, 2010, 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
         
Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows.  We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives and 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 an effectiveness 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.

The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.

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 a discussion of the inputs associated with our fair value measurements.  The following table sets forth the fair values of our derivative instruments for the periods indicated:
 
 
March 31, 2011
December 31, 2010
 
 
Assets (a)
 
(Liabilities) (b)
 
Assets (a)
 
(Liabilities) (b)
 
 
(Thousands of dollars)
 
                 
Commodity derivatives designated as hedging instruments - financial
$ 10,260   $ (27,283 ) $ 13,782   $ (3,556 )
                         
Commodity derivatives not designated as hedging instruments
                       
Financial
  2,260     (2,825 )   2,218     (2,960 )
Physical
  1,641     -     1,616     -  
Total derivatives not designated as hedging instruments
  3,901     (2,825 )   3,834     (2,960 )
Total derivatives
$ 14,161   $ (30,108 ) $ 17,616   $ (6,516 )
(a) - Included on a net basis in other current assets on our Consolidated Balance Sheets.
 
(b) - Included on a net basis in other current liabilities and other liabilities on our Consolidated Balance Sheets.
 
 
Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:
 
      March 31, 2011     December 31, 2010
           
 
Contract
Type
Purchased/
Payor
Sold/
Receiver
Purchased/
Payor
Sold/
Receiver
Derivatives designated as hedging instruments:
               
Cash flow hedges
               
Fixed price
               
- Natural gas (Bcf)
Swaps
                 -
           (6.9)
 
                 -
           (8.2)
 
- Crude oil and NGLs (MMBbl)
Swaps
                 -
           (3.1)
 
                 -
           (1.5)
 
Basis
               
- Natural gas (Bcf)
Swaps
                 -
           (6.9)
 
                 -
           (8.2)
 
                 
Derivatives not designated as hedging instruments:
             
Fixed price
               
- Natural gas (Bcf)
Swaps
             2.0
           (2.0)
 
             2.6
           (2.6)
 
- Crude oil and NGLs (MMBbl)
 Forwards and Swaps
             0.3
           (0.3)
 
             0.6
           (0.6)
 
Basis
               
- Natural gas (Bcf)
Swaps
             2.0
           (2.0)
 
             2.6
           (2.6)
 

Cash Flow Hedges - At March 31, 2011, our Consolidated Balance Sheet reflected a net unrealized loss of $17.0 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 the current levels, we will recognize $11.6 million in losses over the next 12 months, and we will recognize $5.4 million in losses thereafter.

 
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)
2011
 
2010
 
   
(Thousands of dollars)
 
Commodity contracts
Revenues
$ 1,466   $ (4,869 )
Interest-rate contracts
Interest expense
  (208 )   221  
Total gain (loss) reclassified from accumulated other comprehensive
   income (loss) into net income (effective portion)
$ 1,258   $ (4,648 )
 
Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2011 and 2010.  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, 2011 and 2010.

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets at March 31, 2011, and December 31, 2010, was attributable to unrealized gains and losses on derivatives.

Credit Risk - All of our commodity derivative financial contracts are with ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK.  OES has entered into similar commodity derivative financial 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 it may incur solely as a result of its entering into commodity derivative financial contracts on our behalf.  At March 31, 2011, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $9.5 million at December 31, 2010, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors.
 
D.           CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants.  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.  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 increase to 5.5 to 1 for the three calendar quarters following the acquisitions.  At March 31, 2011, our ratio of indebtedness to adjusted EBITDA was 4.17 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.  Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit Agreement may become due and payable immediately.

Our Partnership Credit Agreement is available to repay our commercial paper notes, if necessary.  Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.

A portion of the proceeds from our January 2011 debt issuance, discussed in Note E, was used to repay the outstanding balance of our commercial paper.  At March 31, 2011, we had no commercial paper outstanding and no borrowings under our Partnership Credit Agreement.  As a result of our January 2011 debt offering, available borrowings are limited by the ratio of indebtedness to adjusted EBITDA covenant under our Partnership Credit Agreement.  However, we had approximately $617.4 million of cash at March 31, 2011, and $772.0 million of available borrowings to meet our liquidity needs.  
 
At March 31, 2011, we had no letters of credit issued outside of the Partnership Credit Agreement.  Borrowings under our Partnership Credit Agreement are nonrecourse to our general partner.
 
 
E.           LONG-TERM DEBT
 
Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041.  The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.

These notes are governed by an indenture, dated as of September 25, 2006, between us and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property.  The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of our outstanding senior notes to declare those notes immediately due and payable in full.
 
We may redeem our 3.25-percent senior notes due 2016 and our 6.125-percent senior notes due 2041 at par starting one month and six months, respectively, before their maturities.  Prior to these dates, we may redeem these notes, 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.  Our senior notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any non-guarantor subsidiaries.

F.           EQUITY

ONEOK - ONEOK and its subsidiaries 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, 2011.

Cash Distributions - Cash distributions paid to our general partner of $31.6 million and $26.0 million in the three months ended March 31, 2011 and 2010, respectively, included incentive distributions of $28.6 million and $23.4 million, respectively.

In April 2011, our general partner declared a cash distribution of $1.15 per unit ($4.60 per unit on an annualized basis) for the first quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid on May 13, 2011, to unitholders of record at the close of business on April 29, 2011.

G.           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.  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 Partners GP owns the entire 2-percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels.

For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is generally allocated to the general partner as follows: (i) an amount based upon the 2-percent general partner interest in net income attributable to ONEOK Partners, L.P.; and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period.  The amount of incentive distribution allocated to our general partner totaled $29.6 million and $25.7 million for the three months ended March 31, 2011 and 2010, 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.  For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note H of the Notes to Consolidated Financial Statements in our Annual Report.
 
 
 
H.           UNCONSOLIDATED AFFILIATES
 
Northern Border Pipeline - Northern Border Pipeline anticipates requiring additional equity contributions of approximately $100 million to $120 million from its partners in 2011, of which our share will be approximately $50 million to $60 million based on our 50-percent equity interest.

Overland Pass Pipeline Company - We expect to make contributions in 2011 and 2012 totaling approximately $35 million to $40 million to Overland Pass Pipeline Company to install additional pump stations and to expand existing pump stations.

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2011
 
2010
 
 
(Thousands of dollars)
 
Northern Border Pipeline
$ 20,852   $ 14,846  
Overland Pass Pipeline Company
  4,376     -  
Fort Union Gas Gathering, L.L.C.
  2,965     3,558  
Bighorn Gas Gathering, L.L.C.
  1,493     237  
Lost Creek Gathering Company, L.L.C.
  417     1,402  
Other
  1,989     1,073  
Equity earnings from investments
$ 32,092   $ 21,116  

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,
   
2011
   
2010
 
 
(Thousands of dollars)
Income Statement (a)
           
Operating revenues
 $
 123,301
 
99,231
 
Operating expenses
  $
 54,236
 
 44,715
 
Net income
  $
 63,165
 
 46,911
 
             
Distributions paid to us
  $
 32,511
 
 23,529
 
(a) - Financial information for 2011 is not directly comparable with 2010 due to the deconsolidation of Overland Pass Pipeline Company in September 2010.

I.           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 May 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 operation and maintenance of the Bushton Plant, and we reimburse ONEOK for OBPI’s obligations under equipment leases covering portions of the Bushton Plant.  Pursuant to our rights under the Processing and Services Agreement, on April 22, 2011, we directed OBPI to exercise its purchase option for the original leased equipment (or any replacement parts) pursuant to the terms of the equipment leases.  Our Processing and Services Agreement provides that we will reimburse OBPI for amounts incurred in connection with the exercised option, and upon reimbursement, we will become the owner of the purchased equipment.
 
 
 
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 operates Guardian Pipeline, Viking Pipeline Transmission and Midwestern Gas Transmission according to each pipeline’s operating agreement.  ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement.  ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its 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, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations.  Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK.  In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities.  For example, a service that applies equally to all employees is allocated based upon the number of employees; however, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that includes gross plant and investment, operating income 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 financial 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,
 
2011
 
2010
 
 
(Thousands of dollars)
Revenues
$ 96,793   $ 136,931  
             
Expenses
           
Cost of sales and fuel
$ 10,731   $ 17,759  
Administrative and general expenses
  56,295     51,025  
Total expenses
$ 67,026   $ 68,784  

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $79.9 million and $72.7 million for the three months ended March 31, 2011 and 2010, respectively.

J.           COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical and wildlife preservation laws and environmental regulations affecting many aspects of our present and future operations.  Regulated activities include those involving air emissions, stormwater and wastewater discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction.  These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals.  Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations.  If a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean-up costs, which could affect materially 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, 2011 and 2010.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria.  Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions.  The rule was phased in beginning January 2011 and, at current emission threshold levels, we believe it will have a minimal impact on our existing facilities.  The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

In addition, the EPA has issued a 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 2013.  The 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.

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity- management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas.  Currently, Congress is reauthorizing existing pipeline safety legislation, and there are also a number of new bills addressing pipeline safety being considered.  Recently, the Pipeline and Hazardous Materials Safety Administration issued an “Advisory Bulletin” regarding maximum allowable operating pressures for natural gas and hazardous liquids pipelines.  This bulletin requests all operators review pipeline records and data to validate existing maximum pressure determinations.  We are monitoring activity concerning reauthorization, proposed new legislation and potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations to assess the potential impact on our operations.  At this time, our review of records relating to maximum pressure determinations is ongoing, and no revised or new legislation has been enacted resulting in any potential cost, fees or expenses associated with these issues.  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.

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the more recent proposals.  There may be additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented.  Until the final regulations are established, we are unable to ascertain how we may be affected.  Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation.  We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.

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.

K.           SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments, 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 N 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 - The primary customers for our Natural Gas Gathering and Processing segment are major and independent oil and gas production companies.  Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies, propane distributors, ethanol producers and petrochemical, refining and NGL marketing companies.  Customers served by our Natural Gas Pipelines segment include local distribution companies, power generating companies, natural gas marketing companies and petrochemical companies.

For the three months ended March 31, 2011, our Natural Gas Liquids segment had one customer from which we received 12 percent of our consolidated revenues.  For the three months ended March 31, 2010, we had no customers from which we received 10 percent or more of our consolidated revenues.

See Note I 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, 2011
Natural Gas Gathering and Processing
 
Natural Gas Pipelines (a)
 
Natural Gas Liquids (b)
 
Other and Eliminations
 
Total
 
 
(Thousands of dollars)
 
Sales to unaffiliated customers
$ 65,298   $ 58,716   $ 2,278,803   $ -   $ 2,402,817  
Sales to affiliated customers
  71,826     24,967     -     -     96,793  
Intersegment revenues
  203,451     203     7,238     (210,892 )   -  
Total revenues
$ 340,575   $ 83,886   $ 2,286,041   $ (210,892 ) $ 2,499,610  
                               
Net margin
$ 93,689   75,114   160,255   496   329,554  
Operating costs
  38,027     26,958     43,925     (167 )   108,743  
Depreciation and amortization
  16,162     11,262     15,306     -     42,730  
Loss on sale of assets
  (80 )   (62 )   (368 )   -     (510 )
Operating income
$ 39,420   $ 36,832   $ 100,656   $ 663   $ 177,571  
                               
Equity earnings from investments
$ 6,222   $ 21,038   $ 4,832   $ -   $ 32,092  
Investments in unconsolidated
  affiliates
$ 323,500   $ 387,147   $ 475,941   $ -   $ 1,186,588  
Total assets
$ 1,904,737   $ 1,876,235   $ 4,076,794   $ 624,538   $ 8,482,304  
Noncontrolling interests in
  consolidated subsidiaries
$ -   $ 5,113   $ -   $ 15   $ 5,128  
Capital expenditures
$ 109,523   $ 7,582   $ 27,621   $ 100   $ 144,826  
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $66.1 million, net margin of $57.9 million and operating income of $25.5 million.
 
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $89.4 million, of which $59.9 million related to sales within the segment, net margin of $58.0 million and operating income of $34.1 million.
 

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.
 




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.

RECENT DEVELOPMENTS
 
Growth Projects - In May 2011, we announced plans to invest approximately $910 million to $1.2 billion in our Natural Gas Liquids segment to accommodate growing NGL supplies and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions.
 
Sterling III Pipeline and reconfiguring Sterling I and II Pipelines - We plan to build a 570-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL purity products from the Mid-Continent to the Texas Gulf Coast.  The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for NGL production from the growing Cana-Woodford Shale and Granite Wash, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas.  The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from our natural gas liquids infrastructure at Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas.  Additional pump stations could expand the capacity of the pipeline to 250 MBbl/d.  Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late the same year.

The investment also includes reconfiguring our existing Sterling I and II Pipelines, which currently distributes NGL products between the Mid-Continent and Gulf Coast NGL market centers, to transport either unfractionated NGLs or NGL products.

The project costs for the new pipeline and reconfiguring projects are estimated to be $610 million to $810 million, excluding AFUDC.

MB-2 fractionator - We plan to construct a new 75-MBbl/d fractionator, MB-2, in Mont Belvieu, Texas.  We recently submitted a permit application to the Texas Commission on Environmental Quality (TCEQ) to build this fractionator.  Following the receipt of all necessary permits, construction of the MB-2 fractionator is scheduled to begin in 2011 and is expected to be completed in mid-2013.  The cost of the MB-2 fractionator is estimated to be $300 million to $390 million, excluding AFUDC.  The fractionator can be expanded to 125 MBbl/d to accommodate additional volumes as they are added to the Arbuckle Pipeline, Sterling III Pipeline, and the Sterling I and II reconfiguration.

See discussion of our previously announced growth projects in the “Financial Results and Operating Information” section for our Natural Gas Gathering and Processing and Natural Gas Liquids segments.
 
Cash Distributions - In April 2011, our general partner declared a cash distribution of $1.15 per unit ($4.60 per unit on an annualized basis) for the first quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid May 13, 2011, to unitholders of record at the close of business on April 29, 2011.
 
Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041.  The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.
FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

The following table sets forth certain selected consolidated financial results for the periods indicated:
 
 
Three Months Ended
 
Variances
 
 
March 31,
 
2011 vs. 2010
 
Financial Results
2011
 
2010
 
Increase (Decrease)
 
 
(Millions of dollars)
 
Revenues
$ 2,499.6   $ 2,204.0   $ 295.6     13%  
Cost of sales and fuel
  2,170.1     1,942.9     227.2     12%  
Net margin
  329.5     261.1     68.4     26%  
Operating costs
  108.7     96.2     12.5     13%  
Depreciation and amortization
  42.7     43.9     (1.2 )   (3%)  
Loss on sale of assets
  (0.5 )   (0.8 )   (0.3 )   (38%)  
Operating income
$ 177.6   $ 120.2   $ 57.4     48%  
                         
Equity earnings from investments
$ 32.1   $ 21.1   $ 11.0     52%  
Interest expense
$ (57.3 ) $ (54.2 ) $ 3.1     6%  
Capital expenditures
$ 144.8   $ 35.8   $ 109.0     *  
* Percentage change is greater than 100 percent.
                   

Operating income increased approximately 48 percent for the three months ended March 31, 2011, compared with the same period last year.  The increase in operating income reflects higher net margin in our Natural Gas Liquids segment resulting from the following:
·  
higher optimization margins due primarily to more favorable NGL price differentials, additional fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets; and
·  
higher gathered volumes, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations associated with our natural gas liquids exchange services.

Additionally, our Natural Gas Gathering and Processing segment benefited from higher realized commodity prices and changes in contract terms.

These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company.

Operating costs increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to higher employee-related costs associated with incentive and benefit plans administered by ONEOK and higher ad valorem taxes.
 
Equity earnings from investments increased for the three months ended March 31, 2011, compared with the same period last year, due to increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment from wider natural gas price differentials between the markets it serves, driven by strong Midwest market demand; and the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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 that contains the NGL-rich Cana-Woodford formation 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 includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; 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 natural gas, that does not require processing or NGL extraction in order to be marketable.  Dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.  The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users.  When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream.  This unfractionated NGL stream is shipped to fractionators where, through the application of heat and pressure, the unfractionated NGL stream is separated into NGL products.  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 a 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.  Our natural gas and NGL products are sold to affiliates and also to a diverse customer base.

Growth Projects - We announced in 2010 and early 2011 approximately $950 million to $1.1 billion in growth projects  in the Williston Basin and Cana-Woodford Shale area that will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - We are constructing three new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota.  In addition, we will expand and upgrade our existing gathering and compression infrastructure and add new well connections associated with these plants.  The Garden Creek plant, which is expected to be in service by the end of 2011, and related infrastructure projects are expected to cost approximately $350 million to $415 million, excluding AFUDC.  The Stateline I plant, which is expected to be in service by the third quarter of 2012, and related infrastructure projects are expected to cost approximately $300 million to $355 million, excluding AFUDC.  The Stateline II plant, which is expected to be in service during the first half of 2013, and related infrastructure projects are expected to cost approximately $260 million to $305 million, excluding AFUDC.

Cana-Woodford Shale projects - In 2010, we completed projects totaling approximately $38 million in the Cana-Woodford Shale development in Oklahoma, which included the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma, as well as new well connections to gather and process additional Cana-Woodford Shale volumes.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 34.

 
 
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,
 
2011 vs. 2010
 
Financial Results
2011
 
2010
 
Increase (Decrease)
 
 
(Millions of dollars)
 
NGL and condensate sales
$ 205.2   $ 187.1   $ 18.1     10%  
Residue gas sales
  100.3     131.9     (31.6 )   (24%)  
Gathering, compression, dehydration
  and processing fees and other revenue
  35.1     36.2     (1.1 )   (3%)  
Cost of sales and fuel
  246.9     273.9     (27.0 )   (10%)  
Net margin
  93.7     81.3     12.4     15%  
Operating costs
  38.1     34.4     3.7     11%  
Depreciation and amortization
  16.2     14.7     1.5     10%  
Operating income
$ 39.4   $ 32.2   $ 7.2     22%  
                         
Equity earnings from investments
$ 6.2   $ 5.7   $ 0.5     9%  
Capital expenditures
$ 109.5   $ 19.1   $ 90.4     *  
* Percentage change is greater than 100 percent.
                   
 
Net margin increased for the three months ended March 31, 2011, compared with the same period last year, primarily as result of the following:
·  
an increase of $7.9 million due to higher net realized commodity prices;
·  
an increase of $4.1 million due to changes in contract terms; and
·  
an increase of $2.8 million due to higher volumes processed in the Williston Basin from increased drilling activity in the Bakken Shale, offsetting reduced drilling activity in certain parts of western Oklahoma and Kansas and weather-related outages; offset partially by
·  
a decrease of $2.2 million due to lower volumes gathered as a result of continued production declines and reduced drilling activity by our customers in the Powder River Basin.

Operating costs increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to higher employee-related costs associated with incentive and benefit plans administered by ONEOK.

Depreciation and amortization increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the completion of the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma and the completion of well connections and certain infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to our growth projects discussed above.
 
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 (a)
2011
 
2010
 
Natural gas gathered (BBtu/d)
  992     1,092  
Natural gas processed (BBtu/d)
  641     664  
NGL sales (MBbl/d)
  44     43  
Residue gas sales (BBtu/d)
  274     275  
Realized composite NGL net sales price ($/gallon) (b)
$ 1.09   $ 0.99  
Realized condensate net sales price ($/Bbl) (b)
$ 76.25   $ 62.39  
Realized residue gas net sales price ($/MMBtu) (b)
$ 6.06   $ 5.20  
Realized gross processing spread ($/MMBtu) (b)
$ 8.33   $ 6.37  
(a) - Includes volumes for consolidated entities only.
           
(b) - Presented net of the impact of hedging activities and includes equity volumes only.
 
 
 
Three Months Ended
 
 
March 31,
 
Operating Information (a)
2011
 
2010
 
Percent of proceeds
       
  NGL sales (Bbl/d)
  5,759     5,014  
  Residue gas sales (MMBtu/d)
  41,207     38,395  
  Condensate sales (Bbl/d)
  1,953     1,918  
  Percentage of total net margin
  58%     53%  
Fee-based
           
  Wellhead volumes (MMBtu/d)
  991,778     1,092,061  
  Average rate ($/MMBtu)
$ 0.33   $ 0.30  
  Percentage of total net margin
  33%     36%  
Keep-whole
           
  NGL shrink (MMBtu/d) (b)
  11,971     13,819  
  Plant fuel (MMBtu/d) (b)
  1,347     1,714  
  Condensate shrink (MMBtu/d) (b)
  1,336     1,579  
  Condensate sales (Bbl/d)
  270     320  
  Percentage of total net margin
  9%     11%  
(a) - Includes volumes for consolidated entities only.
           
(b) - Refers to the Btus that are removed from natural gas through processing.
 

 
Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the periods indicated as of May 3, 2011:
 
 
Nine Months Ending
 
 
December 31, 2011
 
   
Volumes Hedged
 
Average Price
 
Percentage Hedged
 
NGLs (Bbl/d) (a)
  5,488   $ 1.18
/ gallon
  66%  
Condensate (Bbl/d) (a)
  1,648   $ 2.14
/ gallon
  77%  
Total (Bbl/d)
  7,136   $ 1.40
/ gallon
  68%  
Natural gas (MMBtu/d)
  25,118   $ 5.60
/ MMBtu
78%  
(a) - Hedged with fixed-price swaps.
                 
                   
 
Year Ending
 
 
December 31, 2012
 
   
Volumes Hedged
 
Average Price
 
Percentage Hedged
 
NGLs (Bbl/d) (a)
  5,169   $ 1.61
/ gallon
  47%  
Condensate (Bbl/d) (a)
  1,819   $ 2.43
/ gallon
  75%  
Total (Bbl/d)
  6,988   $ 1.82
/ gallon
  52%  
(a) - Hedged with fixed-price swaps.
                 
                   
 
Year Ending
 
 
December 31, 2013
 
   
Volumes Hedged
 
Average Price
 
Percentage Hedged
 
NGLs (Bbl/d) (a)
  367   $ 2.55
/ gallon
  2%  
Condensate (Bbl/d) (a)
  649   $ 2.55
/ gallon
  25%  
Total (Bbl/d)
  1,016   $ 2.55
/ gallon
  5%  
(a) - Hedged with fixed-price swaps.
                 

Our Natural Gas Gathering and Processing segment’s commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2011, 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 change in the composite price of NGLs would change annual net margin by approximately $1.3 million;
·  
a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.1 million; and
·  
a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $1.4 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 FERC-regulated interstate natural gas pipeline assets transport natural gas through 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 TransCanada Corporation’s pipeline near Emerson, Manitoba, to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin;
·  
Guardian Pipeline, which interconnects with several pipelines near Joliet, Illinois, and with local distribution companies in Wisconsin; and
·  
OkTex Pipeline Company, which has interconnects in Oklahoma, New Mexico and Texas.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state.  We also have access to the major natural gas producing area in south central Kansas.  In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation 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, which are connected to our intrastate natural gas pipeline assets.

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

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

 
Three Months Ended
 
Variances
 
 
March 31,
 
2011 vs. 2010
 
Financial Results
2011
 
2010
 
Increase (Decrease)
 
 
(Millions of dollars)
 
Transportation revenues
$ 62.5   $ 65.9   $ (3.4 )   (5%)  
Storage revenues
  17.4     16.7     0.7     4%  
Gas sales and other revenues
  4.0     5.0     (1.0 )   (20%)  
Cost of sales
  8.8     9.0     (0.2 )   (2%)  
Net margin
  75.1     78.6     (3.5 )   (4%)  
Operating costs
  27.0     22.8     4.2     18%  
Depreciation and amortization
  11.3     10.9     0.4     4%  
Operating income
$ 36.8   $ 44.9   $ (8.1 )   (18%)  
                         
Equity earnings from investments
$ 21.0   $ 15.1   $ 5.9     39%  
Capital expenditures
$ 7.6   $ 3.2   $ 4.4     *  
* Percentage change is greater than 100 percent.
                   
 
 
 
Three Months Ended
 
 
March 31,
 
Operating Information (a)
2011
 
2010
 
Natural gas transportation capacity contracted (MDth/d) (b)
  5,608     5,906  
Transportation capacity subscribed
  87%     91%  
Average natural gas price
           
Mid-Continent region  ($/MMBtu)
$ 4.10   $ 5.03  
(a) - Includes volumes for consolidated entities only.
           
(b) - Unit of measure converted from MMcf/d in the third quarter of 2010. Prior periods have been recast to reflect this change.
 
 
Net margin decreased for the three months ended March 31, 2011, compared with the same period last year, primarily as a result of the following:
·  
a decrease of $2.8 million from lower natural gas transportation margins, primarily as a result of lower contracted transportation capacity on Midwestern Gas Transmission and lower interruptible transportation volumes due to narrower natural gas price differentials between the markets we serve; and
·  
a decrease of $2.0 million from the impact of lower natural gas prices on our retained fuel positions; offset partially by
·  
an increase of $1.4 million due to higher natural gas storage margins, primarily as a result of higher park-and-loan activity due to periods of higher heating and electric demand.

Operating costs increased for the three months ended March 31, 2011, due primarily to higher ad valorem taxes associated with our previously completed capital projects and higher employee-related costs associated with incentive and benefit plans administered by ONEOK.
 
Equity earnings from investments increased for the three months ended March 31, 2011, compared with the same periods last year, due to increased contracted capacity on Northern Border Pipeline from wider natural gas price differentials between the markets it serves due to strong Midwest market demand.   
 
Natural Gas Liquids

Overview - Our assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas.  We own or have an ownership interest in 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 unprocessed natural gas, are connected to our gathering systems.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline.  Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline-quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content.  The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators 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, ethanol producers, refineries and propane distributors.  We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment.

Revenues for our Natural Gas Liquids segment are derived primarily from fee-based services provided to our customers and physical optimization of our assets.  Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are 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 location and seasonal price differentials.  We transport NGL products between the Mid-Continent and Gulf Coast

 
 
in order to capture the price differentials between the two market centers.  Our natural gas liquids storage facilities are also utilized to capture seasonal price variances;
·  
Our pipeline transportation business transports raw NGLs, finished 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; and
·  
Our storage business collects fees to store NGLs at our Mid-Continent and Mont Belvieu facilities.
 
Growth Projects - In addition to the projects announced in May 2011, we announced in 2010 and early 2011 approximately $830 million to $1.0 billion in NGL-related growth projects, primarily in the Williston Basin, Cana-Woodford Shale and Granite Wash areas.

Bakken Pipeline and related projects - We plan to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, which will transport unfractionated NGLs from the Bakken Shale to the Overland Pass Pipeline.  The Bakken Pipeline will initially have capacity to transport up to 60 MBbl/d of unfractionated NGL production.  The unfractionated NGLs will then be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent.  Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

Supply commitments for the Bakken Pipeline will be anchored by NGL production from our natural gas processing plants.  Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be in service during the first half of 2013.

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline.  These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d.  Our anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

Bushton Fractionator Expansion - To accommodate the additional volume from the Bakken Pipeline, we will invest $110 million to $140 million, excluding AFUDC, to expand and upgrade our existing fractionation capacity at Bushton, Kansas, increasing our capacity to 210 MBbl/d from 150 MBbl/d.  This project is expected to be in service during the first half of 2013.

Cana-Woodford Shale and Granite Wash projects - We plan to invest approximately $197 million to $257 million, excluding AFUDC, in our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. These investments will expand our ability to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute purity NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers.

These investments include constructing more than 230 miles of natural gas liquids pipeline that will expand our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. The pipeline will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded.  Additionally, we will install additional pump stations on our Arbuckle Pipeline to increase its capacity to 240 MBbl/d.  When completed, these projects are expected to add approximately 75 to 80 MBbl/d of unfractionated NGLs to our existing natural gas liquids gathering systems.  These projects are expected to be in service during the first half of 2012 and cost approximately $180 million to $240 million, excluding AFUDC.

We invested approximately $17 million to increase the accessibility of new supply to our Arbuckle Pipeline and Mont Belvieu fractionation facilities.

Sterling I Pipeline Expansion - We are installing seven additional pump stations for approximately $36 million, excluding AFUDC, along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by our Mid-Continent natural gas liquids infrastructure.  The Sterling I pipeline transports purity NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center.  The pump stations are expected to be in service in the second half of 2011.
 
For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 34.
 
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,
 
2011 vs. 2010
 
Financial Results
2011
 
2010
 
Increase (Decrease)
 
 
(Millions of dollars)
 
NGL and condensate sales
$ 2,151.9   $ 1,770.2   $ 381.7     22%  
Exchange service and storage revenues
  116.9     105.1     11.8     11%  
Transportation revenues
  17.3     27.2     (9.9 )   (36%)  
Cost of sales and fuel
  2,125.8     1,798.5     327.3     18%  
Net margin
  160.3     104.0     56.3     54%  
Operating costs
  43.9     41.0     2.9     7%  
Depreciation and amortization
  15.3     18.3     (3.0 )   (16%)  
Loss on sale of assets
  (0.4 )   (0.8 )   (0.4 )   (50%)  
Operating income
$ 100.7   $ 43.9   $ 56.8     *  
                         
Equity earnings from investments
$ 4.8   $ 0.4   $ 4.4     *  
Capital expenditures
$ 27.6   $ 15.8   $ 11.8     75%  
* Percentage change is greater than 100 percent.
                   

 
Three Months Ended
 
 
March 31,
 
Operating Information
2011
 
2010
 
NGL sales (MBbl/d) (a)
  478     427  
NGLs fractionated (MBbl/d) (a)
  488     492  
NGLs transported-gathering lines (MBbl/d) (a) (b)
  397     441  
NGLs transported-distribution lines (MBbl/d) (a)
  461     467  
Conway-to-Mont Belvieu OPIS average price differential
       
  Ethane ($/gallon)
$ 0.15   $ 0.08  
(a) Includes volumes for consolidated entities only.
           
(b) 2010 volume information includes 96 MBbl/d related to Overland Pass Pipeline Company which is accounted for under the equity method in 2011.
 

Net margin increased for the three months ended March 31, 2011, compared with the same period last year, primarily as a result of the following:
·  
an increase of $56.4 million related to higher optimization margins due to more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers;
·  
an increase of $8.9 million related to higher gathered volumes, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations associated with our exchange services; and
·  
an increase of $2.9 million due to higher storage margins as a result of contract renegotiations; offset partially by
·  
a decrease of $11.9 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Operating costs increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the following:
·  
an increase of $2.9 million from higher employee-related costs associated with incentive and benefit plans administered by ONEOK; and
·  
an increase of $1.9 million from higher ad valorem taxes; offset partially by
·  
a decrease of $2.0 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

 
Depreciation and amortization expense decreased, and equity earnings increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to our growth projects discussed above.

CONTINGENCIES

Legal Proceedings - We are a party to various litigation matters and claims that are in the normal course of our operations.  While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.  Additional information about 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, commercial paper, 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.  Capital expenditures are funded by operating cash flow, short- and long-term debt and issuances of equity.  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 three months of 2011, we utilized our commercial paper program, cash from operations and cash available from the January 2011 debt issuance to fund our short-term liquidity needs.  We also used proceeds from our January 2011 debt issuance to fund our capital projects as part of our long-term financing plan.  See discussion below under “Debt Issuance and Maturity” for more information.

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

Capitalization Structure - The following table sets forth our capital structure for the periods indicated:

   
March 31,
 
December 31,
   
2011
 
2010
 
Long-term debt
 
54%
 
46%
 
Equity
 
46%
 
54%
 
Debt (including notes payable)
54%
 
50%
 
Equity
 
46%
 
50%
 
           
Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, our commercial paper program and our Partnership Credit Agreement.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion.  At March 31, 2011, we had no commercial paper outstanding and no borrowings outstanding under our Partnership Credit Agreement. As a result of our January 2011 debt issuance, available borrowings are limited by the 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) covenant under our Partnership Credit Agreement; however, we had approximately $617.4 million of cash at March 31, 2011, and $772.0 million of available borrowings to meet our liquidity needs.  At March 31, 2011, we had no letters of credit issued outside of our Partnership Credit Agreement.

 
Our Partnership Credit Agreement is available to repay the commercial paper notes, if necessary.  Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement.

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants as discussed in Note F 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 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 increase to 5.5 to 1 for the three calendar quarters following the acquisitions. Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partners Credit Agreement may become due and payable immediately.  At March 31, 2011, our ratio of indebtedness to adjusted EBITDA was 4.17 to 1, and we were in compliance with all covenants under 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 our commercial paper program or our existing credit facility, 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 maintain our investment-grade credit ratings.

Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041.  The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.

These notes are governed by an indenture, dated as of September 25, 2006, between us and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.  The indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property.  The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of our outstanding senior notes to declare those notes immediately due and payable in full.

We may redeem our 3.25-percent senior notes due 2016 and our 6.125-percent senior notes due 2041 at par starting one month and six months, respectively, before their maturities.  Prior to these dates, we may redeem these notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued a