OKS-2012.9.30-10Q (1)

10-Q 1 oks-2012930x10q1.htm 10-Q OKS-2012.9.30-10Q (1)

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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 September 30, 2012

___ 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 website, 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 October 26, 2012
Common units		146,827,354 units
Class B units		72,988,252 units

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ONEOK PARTNERS, L.P.

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Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	5
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2012 and 2011	5
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2012 and 2011	6
	Consolidated Balance Sheets - September 30, 2012 and December 31, 2011	7
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	8
	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2012	9
	Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	55
Part II.	Other Information
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	56
Signature		58

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,” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneokpartners.com) copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request. 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.

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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, 2011
ASU	Accounting Standards Update
Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d	Barrels per day
BBtu/d	Billion British thermal units per day
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
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
CFTC	Commodities Futures Trading Commission
Clean Air Act	Federal Clean Air Act, as amended
Clean Water Act	Federal Water Pollution Control Act, as amended
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOT	United States Department of Transportation
EBITDA	Earnings before interest expense, income 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	Kansas Corporation Commission
LIBOR	London Interbank Offered Rate
MBbl	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.
Natural Gas Policy Act	Natural Gas Policy Act of 1978, as amended
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)
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
OKTex Pipeline	OkTex Pipeline Company, L.L.C.
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
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
Partnership 2011 Credit Agreement	The Partnership’s $1.2 billion Revolving Credit Agreement dated August 1, 2011
POP	Percent of Proceeds

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Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
S&P	Standard & Poor’s Rating Services
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
TransCanada	TransCanada Corporation
Viking Gas Transmission	Viking Gas Transmission Company
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION



ITEM 1. FINANCIAL STATEMENTS



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2012			2011			2012			2011
	(Thousands of dollars, except per unit amounts)
Revenues	$	2,547,460		$	2,903,576		$	7,266,354		$	8,187,405
Cost of sales and fuel	2,127,723			2,509,570			6,024,065			7,104,305
Net margin	419,737			394,006			1,242,289			1,083,100
Operating expenses
Operations and maintenance	110,268			96,211			319,905			291,346
Depreciation and amortization	49,754			45,221			150,024			131,665
General taxes	10,908			10,095			40,505			37,284
Total operating expenses	170,930			151,527			510,434			460,295
Gain (loss) on sale of assets	(420		)	(69		)	603			(791		)
Operating income	248,387			242,410			732,458			622,014
Equity earnings from investments (Note H)	28,591			32,029			92,380			93,665
Allowance for equity funds used during construction	3,302			759			6,126			1,625
Other income	2,971			82			6,567			960
Other expense	(472		)	(7,167		)	(2,104		)	(6,249		)
Interest expense (net of capitalized interest of $11,328, $5,967, $29,472 and $12,716, respectively)	(47,776		)	(55,735		)	(148,110		)	(170,626		)
Income before income taxes	235,003			212,378			687,317			541,389
Income taxes	(2,626		)	(2,554		)	(9,396		)	(9,253		)
Net income	232,377			209,824			677,921			532,136
Less: Net income attributable to noncontrolling interests	102			138			336			416
Net income attributable to ONEOK Partners, L.P.	$	232,275		$	209,686		$	677,585		$	531,720
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	232,275		$	209,686		$	677,585		$	531,720
General partner’s interest in net income	(59,807		)	(37,731		)	(163,210		)	(105,376		)
Limited partners’ interest in net income	$	172,468		$	171,955		$	514,375		$	426,344
Limited partners’ net income per unit, basic and diluted (Note G)	$	0.78		$	0.84		$	2.38		$	2.09
Number of units used in computation (thousands)	219,816			203,816			216,241			203,816

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2012			2011			2012			2011
	(Thousands of dollars)
Net income	$	232,377		$	209,824		$	677,921		$	532,136
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(19,361		)	(27,460		)	1,637			(38,118		)
Realized (gains) losses on derivatives recognized in net income	(19,852		)	604			(42,647		)	4,470
Total other comprehensive income (loss)	(39,213		)	(26,856		)	(41,010		)	(33,648		)
Comprehensive income	193,164			182,968			636,911			498,488
Less: Comprehensive income attributable to noncontrolling interests	102			138			336			416
Comprehensive income attributable to ONEOK Partners, L.P.	$	193,062		$	182,830		$	636,575		$	498,072

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
(Unaudited)	2012			2011
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	963,648		$	35,091
Accounts receivable, net	815,403			922,237
Affiliate receivables	14,361			4,132
Gas and natural gas liquids in storage	327,219			202,186
Commodity imbalances	56,861			62,884
Other current assets	103,247			79,343
Total current assets	2,280,739			1,305,873
Property, plant and equipment
Property, plant and equipment	7,977,062			6,963,652
Accumulated depreciation and amortization	1,393,668			1,259,697
Net property, plant and equipment	6,583,394			5,703,955
Investments and other assets
Investments in unconsolidated affiliates (Note H)	1,218,282			1,223,398
Goodwill and intangible assets	647,788			653,537
Other assets	62,390			59,913
Total investments and other assets	1,928,460			1,936,848
Total assets	$	10,792,593		$	8,946,676
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	7,851		$	361,062
Notes payable (Note D)	—			—
Accounts payable	972,192			1,049,284
Affiliate payables	44,228			41,096
Commodity imbalances	213,771			202,542
Other current liabilities	156,980			234,645
Total current liabilities	1,395,022			1,888,629
Long-term debt, excluding current maturities (Note E)	4,805,301			3,515,566
Deferred credits and other liabilities	121,871			95,969
Commitments and contingencies (Note J)
Equity (Note F)
ONEOK Partners, L.P. partners’ equity:
General partner	147,228			106,936
Common units: 146,827,354 and 130,827,354 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively	2,948,360			1,959,437
Class B units: 72,988,252 units issued and outstanding at September 30, 2012 and December 31, 2011	1,462,097			1,426,115
Accumulated other comprehensive loss	(92,098		)	(51,088		)
Total ONEOK Partners, L.P. partners’ equity	4,465,587			3,441,400
Noncontrolling interests in consolidated subsidiaries	4,812			5,112
Total equity	4,470,399			3,446,512
Total liabilities and equity	$	10,792,593		$	8,946,676

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2012			2011
	(Thousands of dollars)
Operating activities
Net income	$	677,921		$	532,136
Depreciation and amortization	150,024			131,665
Allowance for equity funds used during construction	(6,126		)	(1,625		)
Loss (gain) on sale of assets	(603		)	791
Deferred income taxes	5,863			4,999
Equity earnings from investments	(92,380		)	(93,665		)
Distributions received from unconsolidated affiliates	92,996			87,151
Changes in assets and liabilities:
Accounts receivable	106,834			(82,595		)
Affiliate receivables	(10,229		)	(599		)
Gas and natural gas liquids in storage	(125,033		)	73,970
Accounts payable	(76,592		)	91,974
Affiliate payables	3,132			6,713
Commodity imbalances, net	17,252			(67,064		)
Other assets and liabilities	(122,539		)	(28,549		)
Cash provided by operating activities	620,520			655,302
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(1,011,527		)	(662,386		)
Contributions to unconsolidated affiliates	(21,284		)	(51,686		)
Distributions received from unconsolidated affiliates	25,756			16,158
Proceeds from sale of assets	1,663			758
Cash used in investing activities	(1,005,392		)	(697,156		)
Financing activities
Cash distributions:
General and limited partners	(550,978		)	(451,480		)
Noncontrolling interests	(636		)	(343		)
Borrowing (repayment) of notes payable, net	—			(429,855		)
Issuance of long-term debt, net of discounts	1,295,036			1,295,450
Long-term debt financing costs	(9,635		)	(10,986		)
Repayment of long-term debt	(358,948		)	(233,948		)
Issuance of common units, net of issuance costs	919,521			—
Contribution from general partner	19,069			—
Cash provided by financing activities	1,313,429			168,838
Change in cash and cash equivalents	928,557			126,984
Cash and cash equivalents at beginning of period	35,091			898
Cash and cash equivalents at end of period	$	963,648		$	127,882

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
December 31, 2011	130,827,354	72,988,252	$	106,936		$	1,959,437
Net income	—	—	163,210			339,348
Other comprehensive income (loss)	—	—	—			—
Issuance of common units (Note F)	16,000,000	—	—			919,521
Contribution from general partner (Note F)	—	—	19,069			—
Distributions paid (Note F)	—	—	(141,987		)	(269,946		)
September 30, 2012	146,827,354	72,988,252	$	147,228		$	2,948,360

See accompanying Notes to Consolidated Financial Statements.

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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, 2011		$	1,426,115		$	(51,088	)	$	5,112		$	3,446,512
Net income		175,027			—			336			677,921
Other comprehensive income (loss)		—			(41,010		)	—			(41,010		)
Issuance of common units (Note F)		—			—			—			919,521
Contribution from general partner (Note F)		—			—			—			19,069
Distributions paid (Note F)		(139,045		)	—			(636		)	(551,614		)
September 30, 2012		$	1,462,097		$	(92,098	)	$	4,812		$	4,470,399

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ONEOK PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These 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 2011 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

Our 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 May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS. This new guidance changes some fair value measurement principles and disclosure requirements. We adopted this guidance with our March 31, 2012, Quarterly Report, and the impact was not material.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which provides two options for presenting items of net income, other comprehensive income and total comprehensive income, either by creating one continuous statement of comprehensive income or two separate consecutive statements and requires certain other disclosures. In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income. We adopted this guidance, except for the portions deferred by ASU 2011-12, with our March 31, 2012, Quarterly Report, and the impact was not material.

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Under the amendments in this update, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may also resume performing the qualitative assessment in any subsequent period. We adopted this guidance beginning with our July 1, 2012, goodwill impairment test, and it did not impact our financial position or results of operations.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. At July 1, 2012, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.


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. We measure the fair value of groups of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

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. 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

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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 tables set forth our recurring fair value measurements for the periods indicated:



	September 30, 2012
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	—	$	19,784		$	10,715		$	30,499		$	(2,572	)	$	27,927
Liabilities	$	—	$	(1,760	)	$	(812	)	$	(2,572	)	$	2,572		$	—
Derivatives - interest rate
Assets	$	—	$	7,600		$	—		$	7,600		$	—		$	7,600



	December 31, 2011
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	—	$	27,608		$	6,119		$	33,727		$	(3,839	)	$	29,888
Liabilities	$	—	$	(837	)	$	(3,002	)	$	(3,839	)	$	3,839		$	—
Derivatives - interest rate
Liabilities	$	—	$	(77,509	)	$	—		$	(77,509	)	$	—		$	(77,509	)

(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, other assets or other current liabilities in our Consolidated Balance Sheets.

At September 30, 2012, and December 31, 2011, we had no cash collateral held or posted under our master netting arrangements.

Derivative instruments categorized as Level 1 would include exchange-traded contracts that are valued using unadjusted quoted prices in active markets.

Our derivative instruments categorized as Level 2 include nonexchange-traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively. Also, included in Level 2 are our interest-rate swaps that are valued using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.

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 independent broker quotes and observable market information. 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 independent broker quotes compared with actual settlements and correlations.

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Assets (Liabilities)	2012			2011			2012		2011
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	29,862		$	(9,091	)	$	3,117	$	1,156
Total realized/unrealized gains (losses):
Included in earnings (a)	—			1,246			—		133
Included in other comprehensive income (loss)	(19,959		)	8,294			6,786		(840		)
Net assets at end of period	$	9,903		$	449		$	9,903	$	449
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)	$	—		$	1,230		$	—	$	1,230

(a) - Included in revenues in our Consolidated Statements of Income.

During the three and nine months ended September 30, 2012, there were no transfers between levels.

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.

Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $5.5 billion and $4.5 billion at September 30, 2012, and December 31, 2011, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $4.8 billion at September 30, 2012, and $3.9 billion at December 31, 2011. The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. Our long-term debt is classified as Level 2.


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 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 and 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 nonexchange traded; and

•

Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity or other instrument. 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

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are also exposed to basis risk between the various production and market locations where we receive 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.

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 September 30, 2012, and December 31, 2011, 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 September 30, 2012, and December 31, 2011, 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 interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.

We have entered into forward-starting interest-rate swaps designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2011, we had interest-rate swaps with notional values totaling $750 million. During the nine months ended September 30, 2012, we entered into additional interest-rate swaps with notional amounts totaling $650 million. Upon our debt issuance in September 2012, we settled $1 billion of our interest-rate swaps and realized a loss of $124.9 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt. At September 30, 2012, our remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates greater than 12 months.

Accounting Treatment - We record all 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 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, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge

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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 category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.

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 designated as hedging instruments for the periods indicated:



	September 30, 2012					December 31, 2011
	Assets (a)		(Liabilities) (a)			Assets (b)		(Liabilities) (b)
	(Thousands of dollars)
Commodity contracts - financial	$	30,499	$	(2,572	)	$	33,727	$	(3,839	)
Interest-rate contracts	7,600		—			—		(77,509		)
Total derivatives designated as hedging instruments	$	38,099	$	(2,572	)	$	33,727	$	(81,348	)

(a) - Included on a net basis in other current assets and other assets on our Consolidated Balance Sheets.

(b) - Included on a net basis in other current assets, other assets and other current liabilities on our Consolidated Balance Sheets.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments designated as hedging instruments for the periods indicated:



		September 30, 2012					December 31, 2011
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Swaps	—		(22.9		)	—		(21.5		)
- Crude oil and NGLs (MMBbl)	Swaps	—		(2.0		)	—		(2.9		)
Basis
- Natural gas (Bcf)	Swaps	—		(22.9		)	—		(21.5		)
Interest-rate contracts (Millions of dollars)	Forward-starting Swaps	$	400.0	$	—		$	750.0	$	—

Cash Flow Hedges - At September 30, 2012, our Consolidated Balance Sheet reflected a net unrealized loss of $92.1 million in accumulated other comprehensive income (loss). The portion of accumulated other comprehensive income (loss) attributable to our commodity derivative financial instruments is a gain of $27.8 million, which will be realized within the next 15 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $25.8 million in gains over the next 12 months, and we will recognize $2.0 million in gains thereafter. The remaining amounts deferred in accumulated other comprehensive income (loss) are primarily attributable to our interest-rate swaps, of which we expect that losses of $9.5 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Amounts in accumulated other comprehensive income (loss) attributable to forward-starting interest-rate swaps with settlement dates greater than 12 months will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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



	Three Months Ended						Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,						September 30,
Derivatives in Cash Flow Hedging Relationships	2012			2011			2012			2011
	(Thousands of dollars)
Commodity contracts	$	(18,186	)	$	39,588		$	41,469		$	28,930
Interest-rate contracts	(1,175		)	(67,048		)	(39,832		)	(67,048		)
Total gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(19,361	)	$	(27,460	)	$	1,637		$	(38,118	)

The following table sets forth the effect of cash flow hedges on our Consolidated Statements of Income for the periods indicated:



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2012			2011			2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	20,549		$	(514	)	$	43,527		$	(4,082	)
Interest-rate contracts	Interest expense	(697		)	(90		)	(880		)	(388		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income (effective portion)		$	19,852		$	(604	)	$	42,647		$	(4,470	)

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2012 and 2011. 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 and nine months ended September 30, 2012 and 2011.

Credit Risk - All of our commodity derivative financial contracts are with our affiliate, 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. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $27.9 million at September 30, 2012, and $29.9 million at December 31, 2011, respectively, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors. Our interest-rate derivatives are with investment-grade financial institutions.


D.	CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

Partnership 2011 Credit Agreement - Our Partnership 2011 Credit Agreement 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 2011 Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 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 quarter of the acquisition and the two following quarters. Upon breach of certain covenants by us in our Partnership 2011 Credit Agreement, amounts outstanding under our Partnership 2011 Credit Agreement, if any, may become due and payable immediately. At September 30, 2012, our ratio of indebtedness to adjusted EBITDA was 2.9 to 1, and we were in compliance with all covenants under our Partnership 2011 Credit Agreement.

Our Partnership 2011 Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. Our Partnership 2011 Credit Agreement is available to repay our commercial paper notes, if necessary. Amounts outstanding under our commercial paper program reduce

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the borrowing capacity under our Partnership 2011 Credit Agreement. At September 30, 2012, we had no commercial paper outstanding, no letters of credit issued and no borrowings under our Partnership 2011 Credit Agreement.

Effective August 1, 2012, we extended the maturity date of our Partnership 2011 Credit Agreement from August 1, 2016, to August 1, 2017, pursuant to an extension agreement between us and the lenders.


E.	LONG-TERM DEBT

In September 2012, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0-percent senior notes due 2017 and $900 million, 3.375-percent senior notes due 2022. A portion of the net proceeds from the offering of approximately $1.29 billion was used to repay amounts outstanding under our commercial paper program, and the balance will be used for general partnership purposes, including but not limited to 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 2.0-percent senior notes due 2017 and our 3.375-percent senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. Prior to these dates, we may redeem these notes, in whole or in part, 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 nonguarantor subsidiaries.

We used a portion of the proceeds from our March 2012 equity issuance to repay our $350 million, 5.9-percent senior notes due April 2012.

In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million, 3.25-percent senior notes due 2016 and $650 million, 6.125-percent senior notes due 2041. The net proceeds from the offering were approximately $1.28 billion.


F.	EQUITY

ONEOK - ONEOK and its affiliates own all of the Class B units, 19,800,000 common units and the entire 2-percent general partner interest in us, which together constituted a 43.4-percent ownership interest in us at September 30, 2012.

Equity Issuance - In March 2012, we completed an underwritten public offering of 8,000,000 common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million. We also sold 8,000,000 common units to ONEOK in a private placement, generating net proceeds of approximately $460 million. In conjunction with the issuances, ONEOK contributed approximately $19 million in order to maintain its 2-percent general partner interest in us. The net proceeds from the issuances were used to repay $295 million of borrowings under our commercial paper program, to repay amounts on the maturity of our $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures. As a result of these transactions, ONEOK’s aggregate ownership interest increased to 43.4 percent from 42.8 percent.

Partnership Agreement - Available cash, as defined in our Partnership Agreement will generally be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, as set forth in our Partnership Agreement, our general partner receives:


•	15 percent of amounts distributed in excess of $0.3025 per unit;


•	25 percent of amounts distributed in excess of $0.3575 per unit; and


•	50 percent of amounts distributed in excess of $0.4675 per unit.

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Cash Distributions - In October 2012, our general partner declared a cash distribution of $0.685 per unit ($2.74 per unit on an annualized basis) for the third quarter of 2012, an increase of 2.5 cents from the previous quarter, which will be paid on November 14, 2012, to unitholders of record at the close of business on November 5, 2012.

The following table shows our distributions paid in the periods indicated:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.660	$	0.585	$	1.905	$	1.730

General partner distributions	$	3,979	$	3,078	$	11,019	$	9,030
Incentive distributions	49,886		31,580		130,968		89,849
Distributions to general partner	53,865		34,658		141,987		98,879
Limited partner distributions to ONEOK	61,240		49,601		171,882		146,684
Limited partner distributions to other unitholders	83,838		69,631		237,109		205,917
Total distributions paid	$	198,943	$	153,890	$	550,978	$	451,480

The following table shows our distributions declared for the periods indicated and paid within 45 days of the end of the period:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.685	$	0.595	$	1.98	$	1.755

General partner distributions	$	4,199	$	3,159	$	11,937	$	9,233
Incentive distributions	55,162		33,537		149,658		94,741
Distributions to general partner	59,361		36,696		161,595		103,974
Limited partner distributions to ONEOK	63,560		50,449		183,721		148,803
Limited partner distributions to other unitholders	87,014		70,821		251,514		208,893
Total distributions declared	$	209,935	$	157,966	$	596,830	$	461,670


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 conditionally waived its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, 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 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 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.

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H.	UNCONSOLIDATED AFFILIATES

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Northern Border Pipeline Company	$	18,185	$	19,723	$	54,493	$	56,970
Overland Pass Pipeline	4,490		4,338		15,786		14,074
Fort Union Gas Gathering	4,091		3,444		11,494		10,120
Bighorn Gas Gathering	1,157		1,389		3,118		4,727
Other	668		3,135		7,489		7,774
Equity earnings from investments	$	28,591	$	32,029	$	92,380	$	93,665

Unconsolidated Affiliates Financial Information - The following tables set forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	125,828	$	124,955	$	373,038	$	369,258
Operating expenses	$	60,937	$	55,899	$	173,232	$	162,123
Net income	$	55,721	$	65,368	$	180,787	$	187,777
Distributions paid to us	$	34,557	$	32,257	$	118,752	$	103,309

In September 2012, Northern Border Pipeline Company filed with the FERC a settlement with its customers to modify its transportation rates beginning in January 2013. We expect the FERC to make a final ruling on this settlement before the end of the year. If approved, the long-term transportation rates will be approximately 11 percent lower compared with current rates.


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.

Under the Services Agreement with ONEOK, ONEOK Partners GP and NBP Services (the Services Agreement), our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us similar services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP operates 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

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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 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				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Revenues	$	91,096	$	111,177	$	247,851	$	306,669
Expenses
Cost of sales and fuel	$	7,831	$	13,942	$	22,875	$	37,113
Administrative and general expenses	60,020		62,306		179,017		175,815
Total expenses	$	67,851	$	76,248	$	201,892	$	212,928

ONEOK Partners GP made additional general partner contributions to us of approximately $19 million during the nine months ended September 30, 2012, to maintain its 2-percent general partner interest in connection with the issuance of common units. See Note F for additional information about cash distributions paid to ONEOK for its general partner and limited partner interests.


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, storm water 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, licenses and permits 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 cleanup 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, results of operations and cash flows.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2012 and 2011.

In May 2010, the EPA finalized the “Tailoring Rule” that regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are 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, has had 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, with a compliance date in 2013. The rule will require capital expenditures 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.

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In July 2011, the EPA issued a proposed rule that would change the air emission New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and gas industry, including natural gas production, processing, transmission and underground storage. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification. It will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities. However, the EPA is still considering industry comments that may result in the exclusion of certain sources from some of the more costly provisions. If approved, this would reduce the anticipated capital and operations and maintenance costs resulting from the regulation. 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. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The new law increased the maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to:


•	an evaluation of whether hazardous natural gas liquid and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;


•	a review of all natural gas and hazardous natural gas liquid gathering pipeline exemptions;


•	a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and


•	a requirement to test pipelines previously untested in high-consequence areas operating above 30 percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

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. The CFTC has issued final regulations for certain provisions of the Dodd-Frank Act, but others remain outstanding. Several of the regulations became effective in October 2012. Prior to becoming effective, however, one of the final regulations, which imposed federal limits on speculative positions in certain futures contracts, was vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further action. Based on our assessment of the regulations issued to date and those proposed, 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 capital requirements and costs of hedging may increase as a result of the regulations. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

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 reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

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K.	SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments, as follows:


•	our Natural Gas Gathering and Processing segment gathers and processes natural gas;


•	our Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities; and


•	our Natural Gas Liquids segment 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 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 crude oil and natural gas production companies. Customers served by our Natural Gas Pipelines segment include natural gas distribution companies, electric-generation companies, natural gas marketing companies and petrochemical companies. Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies, major and independent crude oil and gas production companies, propane distributors, ethanol producers and petrochemical, refining and NGL marketing companies.

For the three and nine months ended September 30, 2012, and for the three months ended September 30, 2011, we had no single customer from which we received 10 percent or more of our consolidated revenues. For the nine months ended September 30, 2011, our Natural Gas Liquids segment had one customer from which we received 11 percent of our consolidated revenues.

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



Three Months Ended September 30, 2012	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	114,127	$	55,046		$	2,287,191		$	—		$	2,456,364
Sales to affiliated customers	67,269		23,827			—			—			91,096
Intersegment revenues	197,733		910			23,777			(222,420		)	—
Total revenues	$	379,129	$	79,783		$	2,310,968		$	(222,420	)	$	2,547,460
Net margin	$	115,869	$	71,402		$	234,546		$	(2,080	)	$	419,737
Operating costs	39,371		26,265			56,756			(1,216		)	121,176
Depreciation and amortization	19,565		11,592			18,588			9			49,754
Gain (loss) on sale of assets	25		(83		)	(362		)	—			(420		)
Operating income	$	56,958	$	33,462		$	158,840		$	(873	)	$	248,387
Equity earnings from investments	$	5,546	$	18,314		$	4,731		$	—		$	28,591
Capital expenditures	$	157,714	$	5,119		$	212,331		$	127		$	375,291

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $62.4 million, net margin of $54.9 million and operating income of $22.8 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $119.2 million, of which $103.7 million related to sales within the segment, net margin of $68.0 million and operating income of $40.8 million.

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Three Months Ended September 30, 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	$	102,828		$	60,835		$	2,628,736	$	—		$	2,792,399
Sales to affiliated customers	83,151			28,026			—		—			111,177
Intersegment revenues	229,234			651			10,027		(239,912		)	—
Total revenues	$	415,213		$	89,512		$	2,638,763	$	(239,912	)	$	2,903,576
Net margin	$	104,127		$	69,821		$	221,342	$	(1,284	)	$	394,006
Operating costs	35,018			24,385			47,618		(715		)	106,306
Depreciation and amortization	17,259			11,356			16,606		—			45,221
Gain (loss) on sale of assets	(2		)	(77		)	10		—			(69		)
Operating income	$	51,848		$	34,003		$	157,128	$	(569	)	$	242,410
Equity earnings from investments	$	7,991		$	19,776		$	4,262	$	—		$	32,029
Capital expenditures	$	164,954		$	10,629		$	76,477	$	167		$	252,227

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.8 million, net margin of $53.5 million and operating income of $23.5 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $95.5 million, of which $66.2 million related to sales within the segment, net margin of $59.0 million and operating income of $32.4 million.



Nine Months Ended September 30, 2012	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	307,145	$	157,067		$	6,554,291		$	—		$	7,018,503
Sales to affiliated customers	177,213		70,638			—			—			247,851
Intersegment revenues	588,379		2,788			55,902			(647,069		)	—
Total revenues	$	1,072,737	$	230,493		$	6,610,193		$	(647,069	)	$	7,266,354
Net margin	$	332,305	$	212,002		$	703,657		$	(5,675	)	$	1,242,289
Operating costs	120,857		78,291			166,622			(5,360		)	360,410
Depreciation and amortization	61,335		34,525			54,155			9			150,024
Gain (loss) on sale of assets	1,154		(95		)	(456		)	—			603
Operating income	$	151,267	$	99,091		$	482,424		$	(324	)	$	732,458
Equity earnings from investments	$	21,031	$	54,971		$	16,378		$	—		$	92,380
Investments in unconsolidated affiliates	$	323,503	$	406,471		$	488,308		$	—		$	1,218,282
Total assets	$	2,797,692	$	1,855,209		$	5,169,516		$	970,176		$	10,792,593
Noncontrolling interests in consolidated subsidiaries	$	—	$	4,797		$	—		$	15		$	4,812
Capital expenditures	$	435,122	$	14,584		$	561,492		$	329		$	1,011,527

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $179.1 million, net margin of $162.5 million and operating income of $66.8 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $333.9 million, of which $285.8 million related to sales within the segment, net margin of $197.2 million and operating income of $115.5 million.

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Nine Months Ended September 30, 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	$	260,144		$	171,694		$	7,448,898		$	—		$	7,880,736
Sales to affiliated customers	228,780			77,889			—			—			306,669
Intersegment revenues	653,587			1,117			27,278			(681,982		)	—
Total revenues	$	1,142,511		$	250,700		$	7,476,176		$	(681,982	)	$	8,187,405
Net margin	$	298,184		$	213,929		$	572,541		$	(1,554	)	$	1,083,100
Operating costs	109,558			79,133			141,086			(1,147		)	328,630
Depreciation and amortization	50,120			33,902			47,643			—			131,665
Gain (loss) on sale of assets	(208		)	(286		)	(297		)	—			(791		)
Operating income	$	138,298		$	100,608		$	383,515		$	(407	)	$	622,014
Equity earnings from investments	$	21,931		$	57,426		$	14,308		$	—		$	93,665
Investments in unconsolidated affiliates	$	324,018		$	425,570		$	474,809		$	—		$	1,224,397
Total assets	$	2,283,628		$	1,896,337		$	4,474,868		$	120,720		$	8,775,553
Noncontrolling interests in consolidated subsidiaries	$	—		$	5,308		$	—		$	(59	)	$	5,249
Capital expenditures	$	404,112		$	25,178		$	232,698		$	398		$	662,386

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $196.7 million, net margin of $164.3 million and operating income of $69.0 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $278.1 million, of which $189.9 million related to sales within the segment, net margin of $177.3 million and operating income of $100.0 million.


L.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership. The Intermediate Partnership holds all our partnership interests and equity in our subsidiaries, as well as a 50-percent interest in Northern Border Pipeline Company. Our Intermediate Partnership guarantees our senior notes. The Intermediate Partnership’s guarantee is full and unconditional, subject to certain customary automatic release provisions.

For purposes of the following footnote:


•	we are referred to as “Parent”;


•	the Intermediate Partnership is referred to as “Guarantor Subsidiary”; and


•	the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary.

The following unaudited supplemental condensed consolidating financial information is presented on an equity method basis reflecting the Parent’s separate accounts, the Guarantor Subsidiary’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated amounts for the periods indicated.

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Condensed Consolidating Statements of Income



	Three Months Ended September 30, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—			$	2,547.5		$	—		$	2,547.5
Cost of sales and fuel	—			—				2,127.8			—			2,127.8
Net margin	—			—				419.7			—			419.7
Operating expenses
Operations and maintenance	—			—				110.3			—			110.3
Depreciation and amortization	—			—				49.7			—			49.7
General taxes	—			—				10.9			—			10.9
Total operating expenses	—			—				170.9			—			170.9
Gain (loss) on sale of assets	—			—				(0.4		)	—			(0.4		)
Operating income	—			—				248.4			—			248.4
Equity earnings from investments	232.3			232.3				10.4			(446.4		)	28.6
Allowance for equity funds used during construction	—			—				3.3			—			3.3
Other income (expense), net	46.2			46.2				2.5			(92.4		)	2.5
Interest expense	(46.2		)	(46.2		)		(47.8		)	92.4			(47.8		)
Income before income taxes	232.3			232.3				216.8			(446.4		)	235.0
Income taxes	—			—				(2.6		)	—			(2.6		)
Net income	232.3			232.3				214.2			(446.4		)	232.4
Less: Net income attributable to noncontrolling interests	—			—				0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	232.3		$	232.3			$	214.1		$	(446.4	)	$	232.3



	Three Months Ended September 30, 2011
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—			$	2,903.6		$	—		$	2,903.6
Cost of sales and fuel	—			—				2,509.6			—			2,509.6
Net margin	—			—				394.0			—			394.0
Operating expenses
Operations and maintenance	—			—				96.2			—			96.2
Depreciation and amortization	—			—				45.2			—			45.2
General taxes	—			—				10.1			—			10.1
Total operating expenses	—			—				151.5			—			151.5
Gain (loss) on sale of assets	—			—				(0.1		)	—			(0.1		)
Operating income	—			—				242.4			—			242.4
Equity earnings from investments	209.7			209.7				12.3			(399.7		)	32.0
Allowance for equity funds used during construction	—			—				0.8			—			0.8
Other income (expense), net	53.9			53.9				(7.1		)	(107.8		)	(7.1		)
Interest expense	(53.9		)	(53.9		)		(55.7		)	107.8			(55.7		)
Income before income taxes	209.7			209.7				192.7			(399.7		)	212.4
Income taxes	—			—				(2.6		)	—			(2.6		)
Net income	209.7			209.7				190.1			(399.7		)	209.8
Less: Net income attributable to noncontrolling interests	—			—				0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	209.7		$	209.7			$	190.0		$	(399.7	)	$	209.7

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	Nine Months Ended September 30, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—			$	7,266.4		$	—		$	7,266.4
Cost of sales and fuel	—			—				6,024.1			—			6,024.1
Net margin	—			—				1,242.3			—			1,242.3
Operating expenses
Operations and maintenance	—			—				319.9			—			319.9
Depreciation and amortization	—			—				150.0			—			150.0
General taxes	—			—				40.5			—			40.5
Total operating expenses	—			—				510.4			—			510.4
Gain (loss) on sale of assets	—			—				0.6			—			0.6
Operating income	—			—				732.5			—			732.5
Equity earnings from investments	677.6			677.6				37.9			(1,300.7		)	92.4
Allowance for equity funds used during construction	—			—				6.1			—			6.1
Other income (expense), net	143.2			143.2				4.4			(286.4		)	4.4
Interest expense	(143.2		)	(143.2		)		(148.1		)	286.4			(148.1		)
Income before income taxes	677.6			677.6				632.8			(1,300.7		)	687.3
Income taxes	—			—				(9.4		)	—			(9.4		)
Net income	677.6			677.6				623.4			(1,300.7		)	677.9
Less: Net income attributable to noncontrolling interests	—			—				0.3			—			0.3
Net income attributable to ONEOK Partners, L.P.	$	677.6		$	677.6			$	623.1		$	(1,300.7	)	$	677.6



	Nine Months Ended September 30, 2011
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—			$	8,187.4		$	—		$	8,187.4
Cost of sales and fuel	—			—				7,104.3			—			7,104.3
Net margin	—			—				1,083.1			—			1,083.1
Operating expenses
Operations and maintenance	—			—				291.3			—			291.3
Depreciation and amortization	—			—				131.7			—			131.7
General taxes	—			—				37.3			—			37.3
Total operating expenses	—			—				460.3			—			460.3
Gain (loss) on sale of assets	—			—				(0.8		)	—			(0.8		)
Operating income	—			—				622.0			—			622.0
Equity earnings from investments	531.7			531.7				36.7			(1,006.4		)	93.7
Allowance for equity funds used during construction	—			—				1.6			—			1.6
Other income (expense), net	165.0			165.0				(5.3		)	(330.0		)	(5.3		)
Interest expense	(165.0		)	(165.0		)		(170.6		)	330.0			(170.6		)
Income before income taxes	531.7			531.7				484.4			(1,006.4		)	541.4
Income taxes	—			—				(9.3		)	—			(9.3		)
Net income	531.7			531.7				475.1			(1,006.4		)	532.1
Less: Net income attributable to noncontrolling interests	—			—				0.4			—			0.4
Net income attributable to ONEOK Partners, L.P.	$	531.7		$	531.7			$	474.7		$	(1,006.4	)	$	531.7

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Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended September 30, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Net income	$	232.3		$	232.3			$	214.2		$	(446.4	)	$	232.4
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(19.4		)	(18.2		)		(18.2		)	36.4			(19.4		)
Realized (gains) losses on derivatives recognized in net income	(19.8		)	(20.5		)		(20.5		)	41.0			(19.8		)
Total other comprehensive income (loss)	(39.2		)	(38.7		)		(38.7		)	77.4			(39.2		)
Comprehensive income	193.1			193.6				175.5			(369.0		)	193.2
Less: Comprehensive income attributable to noncontrolling interests	—			—				0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	193.1		$	193.6			$	175.4		$	(369.0	)	$	193.1



	Three Months Ended September 30, 2011
(Unaudited)	Parent			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	209.7		$	209.7		$	190.1	$	(399.7	)	$	209.8
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(27.5		)	39.6			39.6		(79.2		)	(27.5		)
Realized (gains) losses on derivatives recognized in net income	0.6			0.5			0.5		(1.0		)	0.6
Total other comprehensive income (loss)	(26.9		)	40.1			40.1		(80.2		)	(26.9		)
Comprehensive income	182.8			249.8			230.2		(479.9		)	182.9
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1		—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	182.8		$	249.8		$	230.1	$	(479.9	)	$	182.8

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	Nine Months Ended September 30, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Net income	$	677.6		$	677.6			$	623.4		$	(1,300.7	)	$	677.9
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	1.6			41.5				41.5			(83.0		)	1.6
Realized (gains) losses on derivatives recognized in net income	(42.6		)	(43.5		)		(43.5		)	87.0			(42.6		)
Total other comprehensive income (loss)	(41.0		)	(2.0		)		(2.0		)	4.0			(41.0		)
Comprehensive income	636.6			675.6				621.4			(1,296.7		)	636.9
Less: Comprehensive income attributable to noncontrolling interests	—			—				0.3			—			0.3
Comprehensive income attributable to ONEOK Partners, L.P.	$	636.6		$	675.6			$	621.1		$	(1,296.7	)	$	636.6



	Nine Months Ended September 30, 2011
(Unaudited)	Parent			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	531.7		$	531.7		$	475.1	$	(1,006.4	)	$	532.1
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(38.1		)	28.9			28.9		(57.8		)	(38.1		)
Realized (gains) losses on derivatives recognized in net income	4.5			4.1			4.1		(8.2		)	4.5
Total other comprehensive income (loss)	(33.6		)	33.0			33.0		(66.0		)	(33.6		)
Comprehensive income	498.1			564.7			508.1		(1,072.4		)	498.5
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.4		—			0.4
Comprehensive income attributable to ONEOK Partners, L.P.	$	498.1		$	564.7		$	507.7	$	(1,072.4	)	$	498.1

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Condensed Consolidating Balance Sheets



	September 30, 2012
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	963.6		$	—	$	—		$	963.6
Accounts receivable, net	—		—			815.4		—			815.4
Affiliate receivables	—		—			14.4		—			14.4
Gas and natural gas liquids in storage	—		—			327.2		—			327.2
Commodity imbalances	—		—			56.9		—			56.9
Other current assets	—		—			103.2		—			103.2
Total current assets	—		963.6			1,317.1		—			2,280.7
Property, plant and equipment
Property, plant and equipment	—		—			7,977.1		—			7,977.1
Accumulated depreciation and amortization	—		—			1,393.7		—			1,393.7
Net property, plant and equipment	—		—			6,583.4		—			6,583.4
Investments and other assets
Investments in unconsolidated affiliates	4,465.6		4,098.0			819.3		(8,164.6		)	1,218.3
Intercompany notes receivable	4,772.2		4,176.2			—		(8,948.4		)	—
Goodwill and intangible assets	—		—			647.8		—			647.8
Other assets	32.3		—			30.1		—			62.4
Total investments and other assets	9,270.1		8,274.2			1,497.2		(17,113.0		)	1,928.5
Total assets	$	9,270.1	$	9,237.8		$	9,397.7	$	(17,113.0	)	$	10,792.6
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—		$	7.9	$	—		$	7.9
Notes payable	—		—			—		—			—
Accounts payable	—		—			972.2		—			972.2
Affiliate payables	—		—			44.2		—			44.2
Commodity imbalances	—		—			213.8		—			213.8
Other current liabilities	68.3		—			88.6		—			156.9
Total current liabilities	68.3		—			1,326.7		—			1,395.0
Intercompany debt	—		4,772.2			4,176.2		(8,948.4		)	—
Long-term debt, excluding current maturities	4,736.2		—			69.1		—			4,805.3
Deferred credits and other liabilities	—		—			121.9		—			121.9
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	4,465.6		4,465.6			3,699.0		(8,164.6		)	4,465.6
Noncontrolling interests in consolidated subsidiaries	—		—			4.8		—			4.8
Total equity	4,465.6		4,465.6			3,703.8		(8,164.6		)	4,470.4
Total liabilities and equity	$	9,270.1	$	9,237.8		$	9,397.7	$	(17,113.0	)	$	10,792.6

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	December 31, 2011
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	35.1		$	—	$	—		$	35.1
Accounts receivable, net	—		—			922.2		—			922.2
Affiliate receivables	—		—			4.1		—			4.1
Gas and natural gas liquids in storage	—		—			202.2		—			202.2
Commodity imbalances	—		—			62.9		—			62.9
Other current assets	—		—			79.4		—			79.4
Total current assets	—		35.1			1,270.8		—			1,305.9
Property, plant and equipment
Property, plant and equipment	—		—			6,963.7		—			6,963.7
Accumulated depreciation and amortization	—		—			1,259.7		—			1,259.7
Net property, plant and equipment	—		—			5,704.0		—			5,704.0
Investments and other assets
Investments in unconsolidated affiliates	3,441.4		4,080.7			807.6		(7,106.3		)	1,223.4
Intercompany notes receivable	3,913.9		3,239.5			—		(7,153.4		)	—
Goodwill and intangible assets	—		—			653.5		—			653.5
Other assets	24.7		—			35.2		—			59.9
Total investments and other assets	7,380.0		7,320.2			1,496.3		(14,259.7		)	1,936.8
Total assets	$	7,380.0	$	7,355.3		$	8,471.1	$	(14,259.7	)	$	8,946.7
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	350.0	$	—		$	11.1	$	—		$	361.1
Accounts payable	—		—			1,049.3		—			1,049.3
Affiliate payables	—		—			41.1		—			41.1
Commodity imbalances	—		—			202.5		—			202.5
Other current liabilities	147.9		—			86.7		—			234.6
Total current liabilities	497.9		—			1,390.7		—			1,888.6
Intercompany debt	—		3,913.9			3,239.5		(7,153.4		)	—
Long-term debt, excluding current maturities	3,440.7		—			74.9		—			3,515.6
Deferred credits and other liabilities	—		—			96.0		—			96.0
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	3,441.4		3,441.4			3,664.9		(7,106.3		)	3,441.4
Noncontrolling interests in consolidated subsidiaries	—		—			5.1		—			5.1
Total equity	3,441.4		3,441.4			3,670.0		(7,106.3		)	3,446.5
Total liabilities and equity	$	7,380.0	$	7,355.3		$	8,471.1	$	(14,259.7	)	$	8,946.7

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Condensed Consolidating Statements of Cash Flows



	Nine Months Ended September 30, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	—		$	54.5			$	566.0		$	—		$	620.5
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—				(1,011.5		)	—			(1,011.5		)
Contributions to unconsolidated affiliates	—			—				(21.3		)	—			(21.3		)
Distributions received from unconsolidated affiliates	—			16.8				8.9			—			25.7
Proceeds from sale of assets	—			—				1.7			—			1.7
Cash provided by (used) in investing activities	—			16.8				(1,022.2		)	—			(1,005.4		)
Financing activities
Cash distributions:
General and limited partners	(551.0		)	(551.0		)		(551.0		)	1,102.0			(551.0		)
Noncontrolling interests	—			—				(0.6		)	—			(0.6		)
Issuance of long-term debt, net of discounts	1,295.0			—				—			—			1,295.0
Long-term debt financing costs	(9.7		)	—				—			—			(9.7		)
Intercompany distributions received	551.0			551.0				—			(1,102.0		)	—
Intercompany borrowings (advances), net	(1,873.9		)	857.2				1,016.7			—			—
Repayment of long-term debt	(350.0		)	—				(8.9		)	—			(358.9		)
Issuance of common units, net of issuance costs	919.5			—				—			—			919.5
Contribution from general partner	19.1			—				—			—			19.1
Cash provided by financing activities	—			857.2				456.2			—			1,313.4
Change in cash and cash equivalents	—			928.5				—			—			928.5
Cash and cash equivalents at beginning of period	—			35.1				—			—			35.1
Cash and cash equivalents at end of period	$	—		$	963.6			$	—		$	—		$	963.6

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	Nine Months Ended September 30, 2011
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries				Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	—		$	57.0			$	598.3		$	—		$	655.3
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—				(662.4		)	—			(662.4		)
Contributions to unconsolidated affiliates	—			(49.8		)		(1.9		)	—			(51.7		)
Distributions received from unconsolidated affiliates	—			16.1				0.1			—			16.2
Proceeds from sale of assets	—			—				0.7			—			0.7
Cash used in investing activities	—			(33.7		)		(663.5		)	—			(697.2		)
Financing activities
Cash distributions:
General and limited partners	(451.5		)	(451.5		)		(451.5		)	903.0			(451.5		)
Noncontrolling interests	—			—				(0.3		)	—			(0.3		)
Intercompany distributions received	451.5			451.5				—			(903.0		)	—
Repayment of notes payable, net	(429.9		)	—				—			—			(429.9		)
Intercompany borrowings (advances), net	(629.6		)	103.7				525.9			—			—
Issuance of long-term debt, net of discounts	1,295.5			—				—			—			1,295.5
Long-term debt financing costs	(11.0		)	—				—			—			(11.0		)
Repayment of long-term debt	(225.0		)	—				(8.9		)	—			(233.9		)
Cash provided by financing activities	—			103.7				65.2			—			168.9
Change in cash and cash equivalents	—			127.0				—			—			127.0
Cash and cash equivalents at beginning of period	—			0.9				—			—			0.9
Cash and cash equivalents at end of period	$	—		$	127.9			$	—		$	—		$	127.9

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ITEM 2.	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 - Oil and gas producers continue to drill aggressively in crude oil and NGL-rich areas, and related development activities continue to progress in many regions where we have operations. We expect continued development of the oil and natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we are investing approximately $5.7 billion to $6.6 billion in new capital projects between 2011 and 2015 to meet the needs of oil and natural gas producers and processors in the Bakken Shale, the Cana-Woodford Shale, Woodford Shale and the Granite Wash and Mississippian Lime areas. In addition, we are investing in NGL infrastructure projects in the Rocky Mountain, Mid-Continent and Gulf Coast regions. These assets will enhance our distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. The execution of these capital investments aligns with our focus to grow fee-based earnings. Our acreage dedications and supply commitments from producers and natural gas processors in regions associated with our growth projects are expected to provide incremental and long-term fee-based earnings and cash flows.

Bakken Crude Express Pipeline - In April 2012, we announced plans to invest $1.5 billion to $1.8 billion to build a 1,300-mile crude-oil pipeline, the Bakken Crude Express Pipeline, with the capacity to transport 200 MBbl/d. The Bakken Crude Express Pipeline will transport light-sweet crude oil primarily from the Bakken Shale and Three Forks formations in the Williston Basin in North Dakota to the Cushing, Oklahoma, market hub.

We are the largest independent gatherer and processor of natural gas in the Williston Basin and currently are constructing a natural gas liquids pipeline, the Bakken NGL Pipeline, to provide needed transportation capacity for the growing NGL production in the area. The development of the Bakken Crude Express Pipeline is a natural addition to the suite of midstream services we currently provide to producers in the Williston Basin and is expected to generate additional fee-based earnings. Additional crude-oil infrastructure is needed due to the continued crude-oil production growth that is expected to exceed the area’s current truck, railcar and pipeline transportation capacity. Our proposed pipeline will provide producers with efficient and reliable transportation capacity directly to one of the largest crude-oil market hubs in the U.S. and will enable producers to maintain the quality of the light-sweet crude oil during transportation.

We began an open season process that provides potential shippers with the opportunity to execute long-term transportation contracts with us in exchange for priority transportation service. The open season began on September 21, 2012, and will conclude on November 20, 2012. Depending upon the level of supply commitments received, the capacity of this pipeline can be increased. More than 80 percent of the proposed pipeline route is expected to parallel our existing and planned natural gas liquids pipelines. Following receipt of sufficient supply commitments, all necessary permits and compliance with customary regulatory requirements, construction is expected to begin in early 2014 and be completed by mid-2015.

See additional discussion of our other growth projects in the “Financial Results and Operating Information” section in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

The following table sets forth certain selected consolidated financial results for the periods indicated:



	Three Months Ended						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2012 vs. 2011					2012 vs. 2011
Financial Results	2012			2011			2012			2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,547.5		$	2,903.6		$	7,266.4		$	8,187.4		$	(356.1	)	(12	%)	$	(921.0	)	(11	%)
Cost of sales and fuel	2,127.8			2,509.6			6,024.1			7,104.3			(381.8		)	(15	%)	(1,080.2		)	(15	%)
Net margin	419.7			394.0			1,242.3			1,083.1			25.7			7	%	159.2			15	%
Operating costs	121.1			106.3			360.4			328.6			14.8			14	%	31.8			10	%
Depreciation and amortization	49.8			45.2			150.0			131.7			4.6			10	%	18.3			14	%
Gain (loss) on sale of assets	(0.4		)	(0.1		)	0.6			(0.8		)	(0.3		)	*		1.4			*
Operating income	$	248.4		$	242.4		$	732.5		$	622.0		$	6.0		2	%	$	110.5		18	%
Equity earnings from investments	$	28.6		$	32.0		$	92.4		$	93.7		$	(3.4	)	(11	%)	$	(1.3	)	(1	%)
Interest expense	$	(47.8	)	$	(55.7	)	$	(148.1	)	$	(170.6	)	$	(7.9	)	(14	%)	$	(22.5	)	(13	%)
Capital expenditures	$	375.3		$	252.2		$	1,011.5		$	662.4		$	123.1		49	%	$	349.1		53	%

* Percentage change is greater than 100 percent.

Revenues decreased for the three and nine months ended September 30, 2012, compared with the same periods last year, due to lower natural gas and NGL product prices, offset partially by higher natural gas and NGL sales volumes from our completed capital projects and more favorable NGL price differentials in the nine-month period. The increase in natural gas supply resulting from the development of resource areas in North America has caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets we serve. NGL prices have also decreased in 2012 due primarily to increased NGL supply from the development of NGL-rich resource areas and periods of lower NGL demand because of scheduled maintenance at Gulf Coast petrochemical plants, and lower crude-oil prices.

The differential between the composite price of NGL products and the price of natural gas, particularly the differential between ethane and natural gas, may influence the volume of NGLs recovered from natural gas processing plants. When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the higher value residue natural gas stream sold at the tailgate of natural gas processing plants. Low commodity prices have resulted in periods of ethane rejection in the Mid-Continent region during 2012. Ethane rejection did not have a material impact on our results for the three and nine months ended September 30, 2012.

The increases in operating income for the three- and nine-month periods reflect higher net margin resulting from higher volumes in the Natural Gas Gathering and Processing and Natural Gas Liquids segments. These increases were offset partially by lower realized natural gas and NGL product prices, particularly ethane and propane. For the nine months ended September 30, 2012, the Natural Gas Liquids segment also benefited from favorable NGL price differentials despite a decline in the third quarter 2012 in these differentials and lower NGL transportation capacity available for optimization activities as compared with the same period in the prior year.

Operating costs increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to the growth of our operations related to our completed capital projects.

Interest expense decreased for three and nine months ended September 30, 2012, compared with the same periods last year, primarily as a result of interest capitalized associated with our investments in the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Capital expenditures increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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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 provide nondiscretionary services to producers that 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 NGL-rich Cana-Woodford Shale and Granite Wash formations, the Mississippian Lime formation of Oklahoma and Kansas 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 gathered, 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 in the form of a mixed, unfractionated NGL stream.

Revenues for this segment are derived primarily from POP and fee-based 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. Keep-whole contracts, which represent less than 5 percent of our contracted volumes, allow us to 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.

We expect that our capital projects will continue to provide additional revenues from POP and fee-based contracts as they are completed. We expect our commodity price exposure to increase, particularly to NGL and natural gas prices, as our equity volumes increase under our POP contracts with our customers in the Williston Basin. We use derivative instruments to mitigate our sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing approximately $1.8 billion to $1.9 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas 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 - In July 2012, we announced plans to invest approximately $310 to $345 million to construct the 100 MMcf/d Garden Creek II natural gas processing plant and related infrastructure. The Garden Creek II plant is expected to be in service during the third quarter of 2014. Combined, our projects in this basin include four 100 MMcf/d natural gas processing facilities: the Garden Creek and Garden Creek II plants located in eastern McKenzie County, North Dakota, and the Stateline I and II plants located in western Williams County, North Dakota. We have acreage dedications of approximately 3.0 million acres supporting these plants. In addition, we are expanding and upgrading our existing natural gas gathering and compression infrastructure and also adding new well connections associated with these plants. The Garden Creek plant was placed in service in December 2011 and together with the related infrastructure cost approximately $360 million, excluding AFUDC. Together, the Stateline I and II plants and related infrastructure projects are expected to cost approximately $560 million to $660 million, excluding AFUDC. The 100 MMcf/d Stateline I natural gas processing facility was placed into service in September 2012, and the 100 MMcf/d Stateline II natural gas processing facility is expected to be in service during the first quarter of 2013.

We plan to invest $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The new system will gather and deliver natural gas from producers in the Williston Basin to both of our Stateline natural gas processing facilities in western Williams County, North Dakota. We have secured long-term supply commitments from producers for this new system, which are structured with POP and fee-based components. This project is expected to be completed in the third quarter of 2013.

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Cana-Woodford Shale projects - We plan to invest approximately $340 million to $360 million to construct a new 200 MMcf/d natural gas processing facility, the Canadian Valley plant, and related infrastructure in the Cana-Woodford Shale in Canadian County, Oklahoma, in close proximity to our existing natural gas transportation and natural gas liquids gathering pipelines. The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where we have substantial acreage dedications from active producers. The new Canadian Valley plant is expected to cost approximately $190 million, excluding AFUDC, and is expected to be in service in the first quarter 2014. The related additional infrastructure is expected to cost approximately $160 million, excluding AFUDC, which we expect will increase our capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.

In both the Williston Basin and Cana-Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells. Horizontal wells drilled in the Williston Basin are justified primarily by crude-oil economics, which are currently very favorable. These wells tend to produce at higher initial volumes resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives. The routine growth capital needed to connect to new wells and expand our infrastructure is expected to increase compared with our previous experience.

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

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				Nine Months Ended					Three Months					Nine Months
	September 30,				September 30,					2012 vs. 2011					2012 vs. 2011
Financial Results	2012		2011		2012		2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	228.5	$	243.5	$	672.2	$	682.7		$	(15.0	)	(6	%)	$	(10.5	)	(2	%)
Residue gas sales	105.4		132.5		270.7		348.2			(27.1		)	(20	%)	(77.5		)	(22	%)
Gathering, compression, dehydration and processing fees and other revenue	45.2		39.2		129.8		111.6			6.0			15	%	18.2			16	%
Cost of sales and fuel	263.2		311.1		740.4		844.3			(47.9		)	(15	%)	(103.9		)	(12	%)
Net margin	115.9		104.1		332.3		298.2			11.8			11	%	34.1			11	%
Operating costs	39.4		35.0		120.9		109.6			4.4			13	%	11.3			10	%
Depreciation and amortization	19.6		17.3		61.3		50.1			2.3			13	%	11.2			22	%
Gain (loss) on sale of assets	0.1		—		1.2		(0.2		)	0.1			*		1.4			*
Operating income	$	57.0	$	51.8	$	151.3	$	138.3		$	5.2		10	%	$	13.0		9	%
Equity earnings from investments	$	5.5	$	8.0	$	21.0	$	21.9		$	(2.5	)	(31	%)	$	(0.9	)	(4	%)
Capital expenditures	$	157.7	$	165.0	$	435.1	$	404.1		$	(7.3	)	(4	%)	$	31.0		8	%

* Percentage change is greater than 100 percent.

Net margin increased for the three months ended September 30, 2012, compared with the same period last year, primarily as a result of the following:


•	an increase of $33.4 million due primarily to volume growth in the Williston Basin from our new Garden Creek natural gas processing plant and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees; offset partially by


•	a decrease of $11.0 million due primarily to lower natural gas and NGL product prices, particularly ethane and propane;


•	a decrease of $9.0 million due primarily to higher compression and processing costs associated with our volume growth primarily in the Williston Basin; and


•	a decrease of $1.6 million due to lower natural gas volumes gathered as a result of continued declines in coal-bed methane production in the Powder River Basin.

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Net margin increased for the nine months ended September 30, 2012, compared with the same period last year, primarily as a result of the following:


•	an increase of $88.8 million due primarily to volume growth in the Williston Basin from our new Garden Creek natural gas processing plant and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees; offset partially by


•	a decrease of $26.4 million due to lower natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices;


•	a decrease of $23.7 million due primarily to higher compression and processing costs associated with our volume growth primarily in the Williston Basin; and


•	a decrease of $4.1 million due to lower natural gas volumes gathered as a result of continued declines in coal-bed methane production in the Powder River Basin.

Operating costs increased for the three months ended September 30, 2012, compared with the same period last year, primarily as a result of the growth of our operations, including the following:


•	an increase of $2.7 million due to higher labor and employee-related costs; and


•	an increase of $1.9 million from higher materials and supplies, and outside services expenses.

Operating costs increased for the nine months ended September 30, 2012, compared with the same period last year, primarily as a result of the growth of our operations, including the following:


•	an increase of $5.0 million due to higher labor and employee-related costs;


•	an increase of $2.9 million from higher materials and supplies, and outside services expenses; and


•	an increase of $1.4 million due to higher property taxes.

Equity earnings decreased for the three months ended September 30, 2012, compared with the same period last year, due primarily to Hurricane Isaac, which interrupted operations at Venice Energy Services Company.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due to the completion of our Garden Creek natural gas processing plant, well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased for the nine months ended September 30, 2012, compared with the same period last year, due primarily to our growth projects discussed above and increased costs for incremental well connections primarily in the Williston Basin. During the third quarter of 2012, we connected approximately 280 new wells to our systems, compared with approximately 180 in the same period last year. For the nine months ended September 30, 2012, we connected approximately 710 new wells to our systems, compared with approximately 420 in the same period last year. We expect to connect more than 900 wells to our systems in 2012.

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				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2012		2011		2012		2011
Natural gas gathered (BBtu/d)	1,149		1,044		1,091		1,021
Natural gas processed (BBtu/d) (b)	906		723		833		682
NGL sales (MBbl/d)	62		50		57		47
Residue gas sales (BBtu/d)	416		348		386		308
Realized composite NGL net sales price ($/gallon) (c)	$	1.10	$	1.09	$	1.07	$	1.09
Realized condensate net sales price ($/Bbl) (c)	$	86.54	$	87.89	$	87.72	$	81.63
Realized residue gas net sales price ($/MMBtu) (c)	$	3.69	$	5.25	$	3.74	$	5.63
Realized gross processing spread ($/MMBtu) (c)	$	8.14	$	8.17	$	8.23	$	8.30
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes processed at company-owned and third-party facilities.
(c) - Presented net of the impact of hedging activities and includes equity volumes only.

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Volumes increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional gathering lines and compression to support our new Garden Creek natural gas processing plant that was placed in service in December 2011, offset partially by continued declines in coal-bed methane production in the Powder River Basin in Wyoming.

Low natural gas prices and the relatively higher market prices of crude oil and NGLs compared with natural gas have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower volumes available to be gathered. While the reserve potential in the Powder River Basin still exists and drilling permits have recently increased, future drilling and development will be affected by commodity prices and producers’ alternative prospects. A continued decline in volumes in this area may reduce our ability to recover the carrying value of our assets and equity investments in this area and could result in noncash charges to earnings.

The quantity and composition of NGLs received by our Natural Gas Gathering and Processing segment as payments under our various processing agreements continue to change as our new natural gas processing plants in the Williston Basin are placed in service. Our Garden Creek and Stateline I plants are capable of but currently are not recovering ethane due to the current lack of natural gas liquids pipeline takeaway transportation capacity. The Natural Gas Liquids segment’s Bakken NGL Pipeline that is expected to be completed in the first quarter of 2013 will enable ethane recovery. As a result, our 2012 equity NGL volumes and realized composite NGL net sales price are weighted more toward the relatively higher priced propane, iso-butane, normal butane and natural gasoline compared with the prior year. This has the effect of producing a higher NGL composite barrel realized price, while most individual NGL products prices are substantially lower this year compared with the prior year.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2012			2011			2012			2011
Percent of proceeds
NGL sales (Bbl/d) (b)	9,941			6,963			9,338			6,433
Residue gas sales (MMBtu/d) (b)	69,952			52,038			63,244			46,702
Condensate sales (Bbl/d) (b)	1,825			1,401			2,180			1,754
Percentage of total net margin	65		%	63		%	63		%	61		%
Fee-based
Wellhead volumes (MMBtu/d)	1,149,072			1,044,385			1,091,063			1,020,871
Average rate ($/MMBtu)	$	0.34		$	0.35		$	0.35		$	0.34
Percentage of total net margin	30		%	31		%	31		%	32		%
Keep-whole
NGL shrink (MMBtu/d) (c)	6,040			9,145			6,643			10,753
Plant fuel (MMBtu/d) (c)	656			973			761			1,193
Condensate shrink (MMBtu/d) (c)	924			801			1,072			1,204
Condensate sales (Bbl/d)	187			162			217			244
Percentage of total net margin	5		%	6		%	6		%	7		%
(a) - Includes volumes for consolidated entities only.
(b) - Represents equity volumes.
(c) - 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 our equity volumes for the periods indicated as of September 30, 2012:



	Three Months Ending December 31, 2012
	Volumes Hedged	(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)	9,488		$	1.25	/ gallon	71%
Condensate (Bbl/d)	1,987		$	2.42	/ gallon	77%
Total (Bbl/d)	11,475		$	1.46	/ gallon	72%
Natural gas (MMBtu/d)	50,109		$	4.54	/ MMBtu	77%
(a) - Hedged with futures and swaps.

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	Year Ending December 31, 2013
	Volumes Hedged	(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)	428		$	2.51	/ gallon	2%
Condensate (Bbl/d)	2,038		$	2.43	/ gallon	70%
Total (Bbl/d)	2,466		$	2.44	/ gallon	10%
Natural gas (MMBtu/d)	50,137		$	3.85	/ MMBtu	80%
(a) - Hedged with futures and swaps.



	Year Ending December 31, 2014
	Volumes Hedged	(a)	Average Price			Percentage Hedged
Natural gas (MMBtu/d)	36,726		$	4.11	/ MMBtu	50%
(a) - Hedged with futures and swaps.

We expect our commodity price sensitivity to increase in the future as volumes increase under POP contracts with our customers. Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at September 30, 2012, 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 $2.8 million;


•	a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.2 million; and


•	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.3 million.

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 owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for nonprocessed gas. We also provide interstate natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act.

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 at the Chicago hub near Joliet, Illinois;


•	Viking Gas Transmission, which transports natural gas from an interconnection with TransCanada’s pipeline near Emerson, Manitoba, to serve local natural gas distribution companies in Minnesota, North Dakota and Wisconsin and terminates at a connection with ANR Pipeline Company near Marshfield, Wisconsin;


•	Guardian Pipeline, which interconnects with several pipelines at the Chicago hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and


•	OkTex Pipeline, which has interconnects in Oklahoma, Texas and New Mexico.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas, including the Cana-Woodford Shale, Granite Wash and Mississippian Lime, 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, including the Granite Wash, and the Permian Basin, and transport natural gas throughout the western portion of the state, including 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.

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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 may be charged, which may 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 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				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2012 vs. 2011					2012 vs. 2011
Financial Results	2012		2011		2012		2011		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	54.9	$	57.7	$	163.8	$	176.1	$	(2.8	)	(5	%)	$	(12.3	)	(7	%)
Storage revenues	17.2		17.3		50.6		51.9		(0.1		)	(1	%)	(1.3		)	(3	%)
Gas sales and other revenues	7.7		14.5		16.1		22.7		(6.8		)	(47	%)	(6.6		)	(29	%)
Cost of sales	8.4		19.7		18.5		36.8		(11.3		)	(57	%)	(18.3		)	(50	%)
Net margin	71.4		69.8		212.0		213.9		1.6			2	%	(1.9		)	(1	%)
Operating costs	26.3		24.4		78.3		79.1		1.9			8	%	(0.8		)	(1	%)
Depreciation and amortization	11.6		11.4		34.5		33.9		0.2			2	%	0.6			2	%
Loss on sale of assets	—		—		0.1		0.3		—			0	%	(0.2		)	(67	%)
Operating income	$	33.5	$	34.0	$	99.1	$	100.6	$	(0.5	)	(1	%)	$	(1.5	)	(1	%)
Equity earnings from investments	$	18.3	$	19.8	$	55.0	$	57.4	$	(1.5	)	(8	%)	$	(2.4	)	(4	%)
Capital expenditures	$	5.1	$	10.6	$	14.6	$	25.2	$	(5.5	)	(52	%)	$	(10.6	)	(42	%)

Net margin increased for the three months ended September 30, 2012, compared with the same period last year, due to higher contracted capacity with natural gas producers on our intrastate pipelines to transport their increasing natural gas supply to market.

Operating costs increased for the three months ended September 30, 2012, compared with the same period last year, primarily as a result of higher outside services costs associated with maintenance projects and higher employee-related costs associated with incentive and benefit plans.

Net margin decreased for the nine months ended September 30, 2012, compared with the same period last year, primarily as a result of the following:


•	a decrease of $3.1 million due primarily to lower prices on our net retained fuel position, offset partially by higher retained fuel volumes; offset partially by


•	an increase of $2.4 million due to higher contracted capacity with natural gas producers on our intrastate pipelines, offset partially by lower contracted capacity on Midwestern Gas Transmission.

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2012			2011			2012			2011
Natural gas transportation capacity contracted (MDth/d)	5,249			5,132			5,345			5,353
Transportation capacity subscribed (b)	87		%	85		%	88		%	88		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.75		$	4.02		$	2.43		$	4.10

(a) - Includes volumes for consolidated entities only.

(b) - Prior periods have been recast to reflect current estimated capacity.

Natural gas transportation capacity contracted increased for the three months ended September 30, 2012, compared with the same period last year due primarily to higher subscribed capacity on Midwestern Gas Transmission as a result of higher contractual capacity with local distribution companies and higher subscribed capacity with producers on our intrastate pipelines to transport their increasing natural gas supply to market.

Our pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies that require natural gas to operate their businesses regardless of location price differentials. The development of shale gas and other unconventional resource areas has continued to increase available natural gas supply and has caused natural gas prices to decrease and location and seasonal price differentials to narrow. As additional supply is being developed, we have begun to contract with producers for firm transportation capacity from supply locations in western Oklahoma and Texas. The firm capacity contracted with producers has helped offset the decrease in contracted capacity by certain customers that are focused on capturing location or seasonal price differentials on some of our pipelines, particularly Midwestern Gas Transmission. The abundance of shale natural gas supply and new regulations on emissions from coal-fired electric-generation plants may also increase the demand for our services from electric-generation companies if they were to convert to a natural gas fuel source. Overall, we expect our fee-based earnings to remain relatively stable in the future as the development of shale and other unconventional resource areas continue.

Our operating information above does not include our 50-percent interest in Northern Border Pipeline Company. Substantially all of Northern Border Pipeline Company’s long-haul transportation capacity has been contracted through March 2014. The Northern Border Pipeline currently operates pursuant to a 2007 rate case settlement. In September 2012, Northern Border Pipeline Company filed with the FERC a settlement with its customers to modify its transportation rates beginning in January 2013. We expect the FERC to make a final ruling on this settlement before the end of the year. If approved, the long-term transportation rates will be approximately 11 percent lower, compared with current rates, which is expected to reduce our future equity earnings from Northern Border Pipeline Company.

Natural Gas Liquids

Overview - Our natural gas liquids assets consist of facilities that gather, fractionate, distribute and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas where we provide nondiscretionary services to producers of NGLs. 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. We own and operate truck and rail-loading and unloading facilities that interconnect with our fractionation and pipeline assets. Through recent expansions to our rail facilities in Kansas, we began receiving raw NGLs transported by rail from the Williston Basin to our Kansas NGL fractionation facilities in early 2012. We will continue to receive these Williston Basin NGLs through our rail-loading facilities until construction is completed on our Bakken NGL Pipeline, which is expected to be in service in the first quarter of 2013.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. 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.

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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 fee-based services have increased due primarily to new supply connections, expansion of existing connections and our previously completed capital projects, including our Cana-Woodford Shale and Granite Wash projects, and expansion of our fractionation capacity and Arbuckle Pipeline. 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 activities primarily collect 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 activities utilize 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 NGL market centers in order to capture the location price differentials between the two locations. Our natural gas liquids storage facilities are also utilized to capture seasonal price variances.


•	Our pipeline transportation business transports unfractionated NGLs, NGL purity products and refined petroleum products primarily under our FERC-regulated tariffs. Tariffs specify the maximum rates we can 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 our isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to increase the octane of motor gasoline.


•	Our storage business collects fees to store NGLs at our Mid-Continent and Gulf Coast facilities.

Growth Projects - Our growth strategy in the Natural Gas Liquids segment is focused around the oil and NGL-rich natural gas drilling activity in shale and other unconventional resource areas from the Rocky Mountain region through the Mid-Continent region into Texas. Increasing crude oil, natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required additional capital investments to expand our infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly over the next five years, and international demand for propane is expected to impact positively the NGL market in the future. Our Natural Gas Liquids segment is investing approximately $2.4 billion to $2.9 billion in NGL-related projects through 2014. These investments will accommodate the transportation and fractionation of growing NGL supplies from shale and other resource development areas across our asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast. Over time, these growing fee-based NGL volumes will fill much of the capacity currently used to capture the NGL price differentials between the two market centers. In addition, we believe the NGL price differentials between the Mid-Continent and Gulf Coast market centers will narrow over the long term as new fractionators and pipelines, including our growth projects discussed below, begin to alleviate constraints affecting NGL prices and location price differentials between the two market centers.

Sterling III Pipeline - 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 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 the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, 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. We have multi-year supply commitments from producers and natural gas processors for approximately 75 percent of the pipeline’s capacity. Installation of 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 distribute 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 are constructing a new 75 MBbl/d fractionator, MB-2, near our storage facility in Mont Belvieu, Texas. The Texas Commission on Environmental Quality (TCEQ) approved our permit application to build this fractionator. Construction began in June 2011 and is expected to be completed in mid-2013. The cost of the new fractionator is

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estimated to be $300 million to $390 million, excluding AFUDC. We have multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity.

MB-3 Fractionator - In July 2012, we announced plans to construct a 75 MBbl/d fractionator, MB-3, near our storage facility in Mont Belvieu, Texas. In addition, we plan to expand and upgrade our existing natural gas liquids gathering and pipeline infrastructure, including new connections to natural gas processing facilities and increasing the capacity of the Arbuckle and Sterling II NGL pipelines. The MB-3 fractionator and related infrastructure are expected to cost approximately $525 million to $575 million, excluding AFUDC. The MB-3 fractionator is expected to be completed in the fourth quarter 2014. Supply commitments from third-party natural gas processors are in various stages of negotiation.

Ethane/Propane Splitter - In July 2012, we announced plans to construct a new 40 MBbl/d ethane/propane splitter at our Mont Belvieu storage facility to split ethane/propane mix into purity ethane in order to meet the growing needs of petrochemical customers. The facility will be capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane, and is expected to be in service during the second quarter 2014. The ethane/propane splitter is expected to cost approximately $45 million, excluding AFUDC.

Bakken NGL Pipeline and related projects - We are building an approximately 600-mile natural gas liquids pipeline, the Bakken NGL Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline. In July 2012, we announced plans to invest an additional $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135 MBbl/d from an initial capacity of 60 MBbl/d. The unfractionated NGLs then will be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Project costs for the new pipeline, including the expansion, are estimated to be $550 million to $650 million, excluding AFUDC. NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from our natural gas processing plants. The 12-inch diameter pipeline is expected to be in service during the first quarter 2013, and the expansion is expected to be completed in the third quarter 2014.

The unfractionated NGLs from the Bakken NGL Pipeline and other supply sources under development in the Rocky Mountain region will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline in which we own a 50-percent equity interest. These additions and expansions will increase the capacity of the 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 - In September 2012, we completed an expansion and upgrade to our existing NGL fractionation capacity at Bushton, Kansas, increasing capacity to 210 MBbl/d from 150 MBbl/d. This additional capacity is necessary to accommodate the volume growth from the Mid-Continent and Williston Basin. The project cost approximately $117 million, excluding AFUDC.

Cana-Woodford Shale and Granite Wash projects - We constructed approximately 230 miles of natural gas liquids pipelines that expanded our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. These pipelines expanded our capacity to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. The pipelines are connected to three new third-party natural gas processing facilities and to three existing third-party natural gas processing facilities that were expanded. Additionally, we installed additional pump stations on our Arbuckle Pipeline to increase its capacity to 240 MBbl/d. These projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to our existing natural gas liquids gathering systems. These projects were placed in service in April 2012 and cost approximately $220 million, excluding AFUDC.

Sterling I Pipeline expansion - In 2011, we installed seven additional pump stations for approximately $30 million, excluding AFUDC, along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which is supplied by our Mid-Continent natural gas liquids infrastructure. The Sterling I Pipeline transports NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center.

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

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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				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2012 vs. 2011					2012 vs. 2011
Financial Results	2012		2011		2012		2011		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,109.1	$	2,488.6	$	6,058.9	$	7,047.3	$	(379.5	)	(15	%)	$	(988.4	)	(14	%)
Exchange service and storage revenues	187.3		137.2		505.8		384.6		50.1			37	%	121.2			32	%
Transportation revenues	14.6		13.0		45.5		44.3		1.6			12	%	1.2			3	%
Cost of sales and fuel	2,076.4		2,417.5		5,906.5		6,903.7		(341.1		)	(14	%)	(997.2		)	(14	%)
Net margin	234.6		221.3		703.7		572.5		13.3			6	%	131.2			23	%
Operating costs	56.8		47.6		166.6		141.1		9.2			19	%	25.5			18	%
Depreciation and amortization	18.6		16.6		54.2		47.6		2.0			12	%	6.6			14	%
Loss on sale of assets	0.4		—		0.5		0.3		0.4			100	%	0.2			67	%
Operating income	$	158.8	$	157.1	$	482.4	$	383.5	$	1.7		1	%	$	98.9		26	%
Equity earnings from investments	$	4.8	$	4.3	$	16.4	$	14.3	$	0.5		12	%	$	2.1		15	%
Capital expenditures	$	212.3	$	76.5	$	561.5	$	232.7	$	135.8		*		$	328.8		*

* Percentage change is greater than 100 percent.

NGL price differentials between Conway, Kansas, and Mont Belvieu, Texas, were narrower for the three-month period and wider for the nine-month period ended September 30, 2012, compared with the same periods last year. The decrease in revenues and cost of sales were the result of lower commodity prices for the three and nine months ended September 30, 2012, compared with the same periods last year. NGL prices have decreased in 2012 due primarily to increased NGL supply from the development of NGL-rich areas and lower NGL demand during periods of the second and third quarters of 2012 because of scheduled maintenance at Gulf Coast petrochemical plants and lower crude oil prices.

Net margin increased for the three months ended September 30, 2012, compared with the same period last year, primarily as a result of the following:


•	an increase of $32.9 million related to higher NGL volumes gathered and fractionated across our systems and contract renegotiations for higher fees associated with our NGL exchange services activities;


•	an increase of $5.8 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes; offset partially by

•

a decrease of $20.9 million in optimization and marketing margins, which resulted from a $43.4 million decrease due to narrower NGL price differentials and lower transportation capacity available for optimization activities, as an increasing portion of our transportation capacity between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers is utilized by our exchange services activities to produce fee-based earnings. This decrease was offset partially by a $22.5 million increase in our marketing activities due primarily to margins realized on the fractionation and sale of NGL inventory held at the end of the second quarter of 2012 associated with the scheduled maintenance at our Mont Belvieu natural gas liquids fractionation facility; and


•	a decrease of $5.5 million due to the impact of higher operational measurement losses.

Net margin increased for the nine months ended September 30, 2012, compared with the same period last year, primarily as a result of the following:


•	an increase of $68.8 million related to higher NGL volumes gathered and fractionated across our systems and contract renegotiations for higher fees associated with our NGL exchange services activities;


•	an increase of $50.3 million in optimization and marketing margins, which resulted primarily from wider NGL product price differentials. Our marketing margins also benefited from higher NGL truck and rail volumes;


•	an increase of $9.6 million due to higher storage margins as a result of contract renegotiations at higher fees;


•	an increase of $3.9 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane; offset partially by


•	a decrease of $1.3 million due to the impact of higher operational measurement losses.

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Operating costs increased for the three months ended September 30, 2012, compared with last year, primarily as a result of the following:


•	an increase of $3.2 million from higher outside services expenses associated primarily with scheduled maintenance and the growth of our operations related to our completed capital projects; and


•	an increase of $4.2 million due to higher labor and employee-related costs associated with the growth of our operations related to our completed capital projects.

Operating costs increased for the nine months ended September 30, 2012, compared with last year, primarily as a result of the following:


•	an increase of $13.2 million from higher materials and outside services expenses associated primarily with scheduled maintenance and the growth of our operations related to our completed capital projects; and


•	an increase of $9.2 million due to higher labor and employee-related costs associated with the growth of our operations related to our completed capital projects.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to the depreciation associated with our completed capital projects.

Equity earnings increased for the three and nine months ended September 30, 2012, due primarily to higher earnings on Overland Pass Pipeline Company in which we own a 50-percent interest, resulting primarily from higher volumes transported.

Capital expenditures increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to expenditures related to our growth projects discussed above.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2012		2011		2012		2011
NGL sales (MBbl/d)	615		485		544		481
NGLs fractionated (MBbl/d) (a)	581		529		565		522
NGLs transported-gathering lines (MBbl/d) (b)	530		443		517		424
NGLs transported-distribution lines (MBbl/d) (b)	504		457		489		460
Conway-to-Mont Belvieu OPIS average price differential
Ethane in ethane/propane mix ($/gallon)	$	0.16	$	0.27	$	0.21	$	0.21

(a) - Includes volumes fractionated at company-owned and third-party facilities.

(b) - Includes volumes for consolidated entities only.

NGLs gathered and fractionated increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to increased throughput from existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions. The increased NGL gathering capacity in the Mid-Continent and Texas was made available through our Cana-Woodford Shale and Granite Wash projects, which were placed in service in April 2012. For the nine months ended September 30, 2012, the increased Gulf Coast fractionation capacity was made available by our 60 Mbl/d fractionation services agreement with Targa Resources Partners that began in the second quarter 2011. For the three months ended September 30, 2012, the increased Mid-Continent fractionation capacity was the result of our Bushton Fractionator expansion, which was completed in September 2012.

NGLs transported on distribution lines increased for the three and nine months ended September 30, 2012, compared with the same periods last year, due primarily to our Sterling I pipeline expansion and higher volumes transported on our distribution pipelines between our Mid-Continent fractionators to optimize the delivery of NGL supply.

CONTINGENCIES

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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 issuance 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 nine months of 2012, we utilized cash from operations, our commercial paper program and proceeds from our March 2012 equity issuance and September 2012 debt issuance to fund our short-term liquidity needs. We also used proceeds from our March 2012 equity issuance and September 2012 debt issuance to repay our $350 million, 5.9-percent senior notes due April 2012 and to fund our capital projects as part of our long-term financing plan. See discussion below under “Long-term Financing” 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 expect to fund our future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

Capital Structure - The following table sets forth our capitalization structure as of the dates indicated:



	September 30,	December 31,
	2012	2011
Long-term debt	52%	53%
Equity	48%	47%
Debt (including notes payable)	52%	53%
Equity	48%	47%

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities and our commercial paper program, which is supported by our Partnership 2011 Credit Agreement.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At September 30, 2012, we had no commercial paper outstanding, no letters of credit issued and no borrowings outstanding under our Partnership 2011 Credit Agreement. At September 30, 2012, we had approximately $963.6 million of cash and $1.2 billion of credit available under the Partnership 2011 Credit Agreement. As of September 30, 2012, we could have issued $3.4 billion of short- and long-term debt to meet our liquidity needs under the most restrictive provisions contained in our various borrowing agreements. Based on the forward LIBOR curve, we expect the interest rates on our short-term borrowings to increase in 2013, compared with interest rates on amounts during 2012.

Our Partnership 2011 Credit Agreement 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 2011 Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 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 quarter of the acquisition and the two following quarters. Upon breach of certain covenants by us in our Partnership 2011 Credit Agreement, amounts outstanding under our Partnership 2011 Credit Agreement, if any, may become due and payable immediately. At September 30, 2012, our ratio of indebtedness to adjusted EBITDA was 2.9 to 1, and we were in compliance with all covenants under our Partnership 2011 Credit Agreement.

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Effective August 1, 2012, we extended the maturity date of our Partnership 2011 Credit Agreement to August 1, 2017 from August 1, 2016, pursuant to an extension agreement between us and the lenders.

Recent events in the European economy could impact European banks. Various European-based banks participate in our Partnership 2011 Credit Agreement, representing an aggregate of $342 million in committed capacity. These banks are of significant scale and international diversification, which we believe minimizes the risk of these banks being unable to fulfill their commitments to us under the Partnership 2011 Credit Agreement. Should any of these banks be unable to fund any future borrowings under our credit agreement, we believe other funding sources would likely be available to replace the commitments of the European banks in our Partnership 2011 Credit Agreement.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term cash requirements by issuing 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 lease back 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 - In September 2012, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0-percent senior notes due 2017 and $900 million, 3.375-percent senior notes due 2022. A portion of the net proceeds from the offering of approximately $1.29 billion was used to repay amounts outstanding under our commercial paper program, and the balance will be used for general partnership purposes, including capital expenditures.

Interest-rate Swaps - We have entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2011, we had interest-rate swaps with notional values totaling $750 million. During the nine months ended September 30, 2012, we entered into additional interest-rate swaps with notional amounts totaling $650 million. Upon our debt issuance in September 2012, we settled $1.0 billion of our interest-rate swaps and realized a loss of $124.9 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt. At

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September 30, 2012, our remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates greater than 12 months.

Capital Expenditures - Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $1.0 billion and $662 million for the nine months ended September 30, 2012 and 2011, respectively. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Maintenance capital expenditures are those required to maintain existing operations and do not generate additional revenues.

The following table summarizes our 2012 projected growth and maintenance capital expenditures, excluding AFUDC:



	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	712	$	26	$	738
Natural Gas Pipelines	3		24		27
Natural Gas Liquids	1,049		54		1,103
Total projected capital expenditures	$	1,764	$	104	$	1,868

Credit Ratings - Our long-term debt credit ratings as of September 30, 2012, are shown in the table below:



Rating Agency	Rating	Outlook
Moody’s	Baa2	Stable
S&P	BBB	Stable

Our commercial paper program is rated Prime-2 by Moody’s and A2 by S&P. Our credit ratings, which are currently investment grade, may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. We do not anticipate a downgrade in our credit ratings; however, if our credit ratings were downgraded, our cost to borrow funds under our commercial paper program or Partnership 2011 Credit Agreement would increase, and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our Partnership 2011 Credit Agreement. An adverse rating change alone is not a default under our Partnership 2011 Credit Agreement.

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

Cash Distributions - We distribute 100 percent of our available cash, as defined in our Partnership Agreement, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Distributions are allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. The effect of any incremental allocations for incentive distributions to our general partner is calculated after the allocation for the general partner’s partnership interest and before the allocation to the limited partners.

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The following table sets forth cash distributions paid, including our general partner’s incentive distribution interests, during the periods indicated:



	Nine Months Ended
	September 30,
	2012		2011
	(Millions of dollars)
Common unitholders	$	270.0	$	226.3
Class B unitholders	139.0		126.3
General partner	142.0		98.9
Noncontrolling interests	0.6		0.3
Total cash distributions paid	$	551.6	$	451.8

In the nine months ended September 30, 2012 and 2011, cash distributions paid to our general partner included incentive distributions of $131.0 million and $89.8 million, respectively.

In October 2012, our general partner declared a cash distribution of $0.685 per unit ($2.74 per unit on an annualized basis) for the third quarter of 2012, an increase of 2.5 cents from the previous quarter, which will be paid on November 14, 2012, to unitholders of record at the close of business on November 5, 2012.

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

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices will impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but do not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, equity earnings from investments net of distributions received from unconsolidated affiliates and changes in our assets and liabilities not classified as investing or financing activities.

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



	Nine Months Ended						Variances
	September 30,						2012 vs. 2011
	2012			2011			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	620.5		$	655.3		$	(34.8	)
Investing activities	(1,005.4		)	(697.1		)	(308.3		)
Financing activities	1,313.4			168.8			1,144.6
Change in cash and cash equivalents	928.5			127.0			801.5
Cash and cash equivalents at beginning of period	35.1			0.9			34.2
Cash and cash equivalents at end of period	$	963.6		$	127.9		$	835.7

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Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or competition from other service providers, could affect our earnings and operating cash flows.

Cash flows from operating activities, before changes in operating assets and liabilities, were $827.7 million for the nine months ended September 30, 2012, compared with $661.5 million for the same period in 2011. The increase was due primarily to an increase in net margin as discussed in “Financial Results and Operating Information” and higher distributed earnings from our unconsolidated affiliates.

The changes in operating assets and liabilities decreased operating cash flows $207.2 million for the nine months ended September 30, 2012, compared with a decrease of $6.2 million for the same period in 2011. The change is due primarily to the increase in natural gas and natural gas liquids volumes in storage, offset partially by lower commodity prices and the settlement of our interest-rate swaps associated with our $1.3 billion debt issuance in September 2012. The change is also due to the change in accounts receivable resulting from the timing of receipt of cash from customers, as well as accounts payable and the timing of payments to vendors and suppliers, which vary from period to period.

Investing Cash Flows - Cash used in investing activities increased for the nine months ended September 30, 2012, compared with the same period in 2011, due primarily to increased capital expenditures on our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Financing Cash Flows - Cash provided by financing activities increased during the nine months ended September 30, 2012, compared with an increase for the same period in 2011. The change is a result of net proceeds of $938.6 million from our equity issuances in 2012, partially offset by a $350 million debt maturity and higher cash distributions, compared with the same period in 2011, which included a $225 million debt maturity and a net repayment of $430 million of commercial paper. Financing cash flows also reflect net proceeds from our debt issuances of $1.3 billion in the nine months ended September 30, 2012 and 2011.

REGULATORY

ENVIRONMENTAL AND SAFETY MATTERS

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

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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, results of operations and cash flows.


•	an evaluation of whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;


•	a review of all natural gas and hazardous natural gas liquid gathering pipeline exemptions;


•	a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and


•	a requirement to test pipelines previously untested in high-consequence areas operating above 30 percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

Air and Water Emissions - The Clean Air Act, the Clean Water Act and analogous state laws impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule released in September 2009 requires greenhouse gas emissions reporting for affected facilities on an annual basis and requires us to track the emission equivalents for all NGLs delivered to our customers. Our 2010 total reported emissions were less than 53.2 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers, as if all such fuel and NGL products were combusted with the resulting carbon dioxide injected directly into disposal wells. We reported 2011 greenhouse gas emissions for a portion of our facilities by March 31, 2012, as required by the EPA, and for the remainder of our facilities by September 30, 2012. Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due September 30, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered and may consider in the future legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

In May 2010, the EPA finalized the “Tailoring Rule” that regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are 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 has had 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, with a compliance date in 2013. The rule will require capital expenditures over the next two 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.

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Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances

found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. In 2011, we received notice from the EPA of potential liability at the U.S. Oil Recovery Superfund Site location in Harris County, Texas. We are named a potentially responsible party as a result of waste disposal at the now-abandoned site. We do not expect our responsibilities under CERCLA, for this facility or any other, to have a material impact on our results of operations, financial position or cash flows.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. We completed the Homeland Security assessments, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, four of our facilities have been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

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

We participate in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

IMPACT OF NEW ACCOUNTING STANDARDS

See Note A of the Notes to Consolidated Financial Statements for discussion of new accounting standards.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial

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statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

We review our goodwill for impairment at least annually, and we evaluated our goodwill for impairment as of July 1, 2012. Our goodwill impairment analysis performed on that date did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.

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

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.

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


•	the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;


•	competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;


•	the capital intensive nature of our businesses;


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


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


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


•	the uncertainty of estimates, including accruals and costs of environmental remediation;


•	the timing and extent of changes in energy commodity prices;


•	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;


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


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


•	changes in demand for the use of natural gas and crude oil because of market conditions caused by concerns about global warming;


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


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

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


•	actions by rating agencies concerning the credit ratings of us or the parent of our general partner;


•	the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the Pipeline and Hazardous Materials Safety Administration, the EPA and CFTC;


•	our ability to access capital at competitive rates or on terms acceptable to us;


•	risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling;


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


•	the impact and outcome of pending and future litigation;


•	the ability to market pipeline capacity on favorable terms, including the effects of:

- future demand for and prices of natural gas, NGLs and crude oil;

- competitive conditions in the overall energy market;

- availability of supplies of Canadian and United States natural gas and crude oil; and

- availability of additional storage capacity;


•	performance of contractual obligations by our customers, service providers, contractors and shippers;


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


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


•	the mechanical integrity of facilities operated;


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


•	our ability to control operating costs;


•	acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;


•	economic climate and growth in the geographic areas in which we do business;


•	the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;


•	the impact of recently issued and future accounting updates and other changes in accounting policies;


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


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


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


•	the impact of uncontracted capacity in our assets being greater or less than expected;


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


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


•	the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;


•	the impact of potential impairment charges;


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


•	our ability to control construction costs and completion schedules of our pipelines and other projects; and


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

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

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

INTEREST RATE RISK

We have entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2011, we had interest-rate swaps with notional values totaling $750 million. During the nine months ended September 30, 2012, we entered into additional interest-rate swaps with notional amounts totaling $650 million. Upon our debt issuance in September 2012, we settled $1.0 billion of our interest-rate swaps and realized a loss of $124.9 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt. At September 30, 2012, our remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates greater than 12 months.


ITEM 4.	CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - The Chief Executive Officer and the Chief Financial Officer of ONEOK Partners GP, our general partner, who are the equivalent of our principal executive and principal financial officers, have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the third quarter ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al., f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”). On September 19, 2012, the Court dismissed without prejudice all of the ONEOK defendants from the case, other than ONEOK Field Services Company, L.L.C.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”). On September 19, 2012, the Court dismissed without prejudice all of the ONEOK defendants from the case, other than ONEOK Field Services Company, L.L.C.


ITEM 1A.	RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors, of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not Applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.


ITEM 5.	OTHER INFORMATION

Not Applicable.


ITEM 6.	EXHIBITS

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

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The following exhibits are filed as part of this Quarterly Report:



Exhibit No.		Exhibit Description

	4.1	Eighth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 2.000% Senior Notes due 2017 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 13, 2012 (File No. 1-12202)).

	4.2	Ninth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.375% Senior Notes due 2022 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 13, 2012 (File No. 1-12202)).

	10.1	Underwriting Agreement, dated September 10, 2012, among ONEOK Partners, L.P. and ONEOK Partners Intermediate Limited Partnership and RBS Securities Inc., Mitsubishi UFJ Securities (USA), Inc. and U.S. Bancorp Investments, Inc., as representative of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 13, 2012 (File No. 1-12202)).

	10.2	Extension Agreement, dated August 1, 2012, among ONEOK Partners, L.P., as Borrower, each of the existing Lenders and Citibank, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference from Exhibit 10.1 to ONEOK Partners, L.P.’s Quarerly Report on 10-Q filed on August 1, 2012 (File No. 1-12202)).

	31.1	Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of Robert F. Martinovich pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

	32.2	Certification of Robert F. Martinovich pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Calculation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definitions Document.

	101.LAB	XBRL Taxonomy Label Linkbase Document.

	101.PRE	XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2012 and 2011; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2012 and 2011; (iv) Consolidated Balance Sheets at September 30, 2012 and December 31, 2011; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011; (vi) Consolidated Statement of Changes in Equity for the nine months ended September 30, 2012; and (vii) Notes to Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

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

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SIGNATURE

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



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

Date: October 31, 2012		By: /s/ Robert F. Martinovich
		Robert F. Martinovich
		Executive Vice President,
		Chief Financial Officer and Treasurer
		(Signing on behalf of the Registrant)