OKS-2013.3.31-10Q

10-Q 1 oks-2013331x10q.htm OKS MARCH 31, 2013 10-Q OKS-2013.3.31-10Q

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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 March 31, 2013.

___ 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 April 25, 2013
Common units		147,127,354 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)	6
	Consolidated Statements of Income - Three Months Ended March 31, 2013 and 2012	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2013 and 2012	7
	Consolidated Balance Sheets - March 31, 2013 and December 31, 2012	8
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2013 and 2012	9
	Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2013	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	52
Part II.	Other Information
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	Mine Safety Disclosures	53
Item 5.	Other Information	53
Item 6.	Exhibits	53
Signature		55

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, 2012
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
Bighorn Gas Gathering	Bighorn Gas Gathering, L.L.C.
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 Amendments of 1972, 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
Fort Union Gas Gathering	Fort Union Gas Gathering, L.L.C.
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.
LIBOR	London Interbank Offered Rate
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 Act	Natural Gas Act of 1938, as amended
Natural Gas Policy Act	Natural Gas Policy Act of 1978, as amended
NGL products	Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NGL(s)	Natural gas liquid(s)
Northern Border Pipeline	Northern Border Pipeline Company
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ONEOK	ONEOK, Inc.
ONEOK Partners GP	ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners
OPIS	Oil Price Information Service
Overland Pass Pipeline Company	Overland Pass Pipeline Company LLC
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
Partnership Credit Agreement	The Partnership’s $1.2 billion Revolving Credit Agreement dated August 1, 2011, as amended

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PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP	Percent of Proceeds
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
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
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars, except per unit amounts)
Revenues	$	2,517,447		$	2,594,088
Cost of sales and fuel	2,146,848			2,172,998
Net margin	370,599			421,090
Operating expenses
Operations and maintenance	121,289			100,367
Depreciation and amortization	54,678			49,256
General taxes	16,975			15,503
Total operating expenses	192,942			165,126
Gain on sale of assets	41			57
Operating income	177,698			256,021
Equity earnings from investments (Note H)	25,855			34,620
Allowance for equity funds used during construction	9,087			975
Other income	3,705			5,471
Other expense	(1,481		)	(1,278		)
Interest expense (net of capitalized interest of $12,605 and $8,736, respectively)	(55,872		)	(53,209		)
Income before income taxes	158,992			242,600
Income taxes	(2,307		)	(3,636		)
Net income	156,685			238,964
Less: Net income attributable to noncontrolling interests	86			121
Net income attributable to ONEOK Partners, L.P.	$	156,599		$	238,843
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	156,599		$	238,843
General partner’s interest in net income	(64,708		)	(49,387		)
Limited partners’ interest in net income	$	91,891		$	189,456
Limited partners’ net income per unit, basic and diluted (Note G)	$	0.42		$	0.91
Number of units used in computation (thousands)	219,861			209,090

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
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars)
Net income	$	156,685		$	238,964
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(12,980		)	30,026
Realized gains on derivatives recognized in net income	(261		)	(6,606		)
Total other comprehensive income (loss)	(13,241		)	23,420
Comprehensive income	143,444			262,384
Less: Comprehensive income attributable to noncontrolling interests	86			121
Comprehensive income attributable to ONEOK Partners, L.P.	$	143,358		$	262,263

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2013			2012
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	68,923		$	537,074
Accounts receivable, net	778,379			914,036
Affiliate receivables	21,952			16,092
Gas and natural gas liquids in storage	228,833			235,836
Commodity imbalances	75,274			89,704
Other current assets	69,760			98,966
Total current assets	1,243,121			1,891,708
Property, plant and equipment
Property, plant and equipment	9,008,682			8,585,142
Accumulated depreciation and amortization	1,490,407			1,440,871
Net property, plant and equipment	7,518,275			7,144,271
Investments and other assets
Investments in unconsolidated affiliates (Note H)	1,220,129			1,221,405
Goodwill and intangible assets	643,955			645,871
Other assets	70,527			55,975
Total investments and other assets	1,934,611			1,923,251
Total assets	$	10,696,007		$	10,959,230
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	7,650		$	7,650
Notes payable (Note D)	—			—
Accounts payable	971,163			1,058,007
Affiliate payables	45,338			75,710
Commodity imbalances	202,186			273,173
Accrued interest	87,481			76,734
Other current liabilities	67,970			79,158
Total current liabilities	1,381,788			1,570,432
Long-term debt, excluding current maturities	4,801,966			4,803,629
Deferred credits and other liabilities	109,836			121,662
Commitments and contingencies (Note J)
Equity (Note E)
ONEOK Partners, L.P. partners’ equity:
General partner	152,698			152,513
Common units: 147,127,354 and 146,827,354 units issued and outstanding at March 31, 2013 and December 31, 2012, respectively	2,918,385			2,945,051
Class B units: 72,988,252 units issued and outstanding at March 31, 2013 and December 31, 2012	1,439,191			1,460,498
Accumulated other comprehensive loss (Note F)	(112,563		)	(99,322		)
Total ONEOK Partners, L.P. partners’ equity	4,397,711			4,458,740
Noncontrolling interests in consolidated subsidiaries	4,706			4,767
Total equity	4,402,417			4,463,507
Total liabilities and equity	$	10,696,007		$	10,959,230

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars)
Operating activities
Net income	$	156,685		$	238,964
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	54,678			49,256
Allowance for equity funds used during construction	(9,087		)	(975		)
Gain on sale of assets	(41		)	(57		)
Deferred income taxes	1,502			1,868
Equity earnings from investments	(25,855		)	(34,620		)
Distributions received from unconsolidated affiliates	23,495			36,879
Changes in assets and liabilities:
Accounts receivable	139,043			85,618
Affiliate receivables	(5,860		)	(3,689		)
Gas and natural gas liquids in storage	7,003			91,578
Accounts payable	(62,293		)	(104,128		)
Affiliate payables	(30,372		)	(17,447		)
Commodity imbalances, net	(56,557		)	(103,384		)
Accrued interest	10,747			6,316
Other assets and liabilities, net	(21,651		)	(27,013		)
Cash provided by operating activities	181,437			219,166
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(443,464		)	(280,793		)
Contributions to unconsolidated affiliates	(3,036		)	(2,577		)
Distributions received from unconsolidated affiliates	6,698			4,062
Proceeds from sale of assets	47			413
Cash used in investing activities	(439,755		)	(278,895		)
Financing activities
Cash distributions:
General and limited partners	(220,924		)	(164,083		)
Noncontrolling interests	(147		)	(245		)
Repayment of long-term debt	(1,913		)	(2,983		)
Issuance of common units, net of issuance costs	12,819			919,576
Contribution from general partner	332			19,069
Cash provided by (used in) financing activities	(209,833		)	771,334
Change in cash and cash equivalents	(468,151		)	711,605
Cash and cash equivalents at beginning of period	537,074			35,091
Cash and cash equivalents at end of period	$	68,923		$	746,696

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)
January 1, 2013	146,827,354	72,988,252	$	152,513		$	2,945,051
Net income	—	—	64,708			61,376
Other comprehensive loss (Note F)	—	—	—			—
Issuance of common units (Note E)	300,000	—	—			16,205
Contribution from general partner (Note E)	—	—	332			—
Distributions paid (Note E)	—	—	(64,855		)	(104,247		)
March 31, 2013	147,127,354	72,988,252	$	152,698		$	2,918,385

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)
January 1, 2013		$	1,460,498		$	(99,322	)	$	4,767		$	4,463,507
Net income		30,515			—			86			156,685
Other comprehensive loss (Note F)		—			(13,241		)	—			(13,241		)
Issuance of common units (Note E)		—			—			—			16,205
Contribution from general partner (Note E)		—			—			—			332
Distributions paid (Note E)		(51,822		)	—			(147		)	(221,071		)
March 31, 2013		$	1,439,191		$	(112,563	)	$	4,706		$	4,402,417

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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 2012 year-end consolidated balance sheet data was derived from our 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 February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source. This guidance is effective for our interim and annual periods beginning on January 1, 2013, and is applied prospectively. We adopted this guidance with this Quarterly Report, and it did not impact our financial position or results of operations. See Note F for additional disclosures.

In December 2011, the FASB issued ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance is effective for interim and annual periods beginning on January 1, 2013, and is applied retrospectively for all comparative periods presented. We adopted this guidance beginning with this Quarterly Report, and it did not impact our financial position or results of operations. See Note B for additional disclosures.


B.	FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the income approach to determine the fair value of our derivative assets and liabilities and consider the markets in which the transactions are executed. 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. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data, historical correlations of NGL product prices to crude oil prices and implied forward LIBOR curves. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using 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 material.

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



	March 31, 2013
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives assets
Commodity contracts - financial	$	—	$	4,399		$	2,483		$	6,882		$	(6,882	)	$	—
Interest-rate contracts	—		17,711			—			17,711			—			17,711
Total derivative assets	$	—	$	22,110		$	2,483		$	24,593		$	(6,882	)	$	17,711

Derivatives liabilities
Commodity contracts
Financial contracts	$	—	$	(6,706	)	$	(4,167	)	$	(10,873	)	$	6,882		$	(3,991	)
Physical contracts	—		—			(3,171		)	(3,171		)	—			(3,171		)
Total derivative liabilities	$	—	$	(6,706	)	$	(7,338	)	$	(14,044	)	$	6,882		$	(7,162	)



	December 31, 2012
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (c)
	(Thousands of dollars)
Derivatives assets
Commodity contracts - financial	$	—	$	17,581		$	1		$	17,582		$	(2,455	)	$	15,127
Interest-rate contracts	—		10,923			—			10,923			—			10,923
Total derivative assets	$	—	$	28,504		$	1		$	28,505		$	(2,455	)	$	26,050

Derivatives liabilities
Commodity contracts - financial	$	—	$	(31	)	$	(2,424	)	$	(2,455	)	$	2,455		$	—
Total derivative liabilities	$	—	$	(31	)	$	(2,424	)	$	(2,455	)	$	2,455		$	—

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

At March 31, 2013, and December 31, 2012, we had no cash collateral held or posted under our master-netting arrangements.

Our Level 1 fair value would include amounts based on unadjusted quoted prices in active markets including NYMEX-settled prices. These balances would be comprised predominantly of NYMEX-traded derivative contracts for natural gas and crude oil.

Our Level 2 fair value amounts are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps.

Our Level 3 fair value amounts are based on inputs that may include one or more unobservable inputs including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and natural gas liquids.

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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
	March 31,
Derivative Assets (Liabilities)	2013			2012
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	(2,423	)	$	3,117
Total realized/unrealized gains (losses):
Included in other comprehensive income (loss)	(2,432		)	5,559
Net assets (liabilities) at end of period	$	(4,855	)	$	8,676

During the three months ended March 31, 2013 and 2012, gains or losses included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held at the end of the period were not material. During the three months ended March 31, 2013 and 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 $5.6 billion at March 31, 2013, and December 31, 2012, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $4.8 billion at March 31, 2013, and December 31, 2012. 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. The estimated fair value of 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 contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;


•	Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties; and


•	Swaps - Exchange of one or more payments based on the value of one or more commodities. This transfers the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability.

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. Less than 2 percent of our contracted volume exposure arises from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to our keep-whole contracts. We are also exposed to basis risk between the various production and market locations where we receive and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts 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

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the regulatory treatment for this activity. To the extent that commodity-price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we use physical forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At March 31, 2013, and December 31, 2012, there were no financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity-price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical-forward contracts to reduce the impact of price fluctuations related to NGLs. At March 31, 2013, and December 31, 2012, 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. At March 31, 2013, and December 31, 2012, we had forward-starting interest-rate swaps with notional amounts totaling $400 million with settlement dates greater than 12 months that have been 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.

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 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.

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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, all of which were designated as cash flow hedges for the periods indicated:



	March 31, 2013					December 31, 2012
	Assets (a)		(Liabilities) (a)			Assets (b)		(Liabilities) (b)
	(Thousands of dollars)
Commodity contracts - financial	$	6,882	$	(10,873	)	$	17,582	$	(2,455	)
Commodity contracts - physical	—		(3,171		)	—		—
Interest-rate contracts	17,711		—			10,923		—
Total derivatives designated as hedging instruments	$	24,593	$	(14,044	)	$	28,505	$	(2,455	)

(a) - Included on a net basis in other assets, other current liabilities or deferred credits and other liabilities 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:



		March 31, 2013					December 31, 2012
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Swaps	—		(56.3		)	—		(31.7		)
- Crude oil and NGLs (MMBbl)	Forwards and swaps	—		(3.5		)	—		(1.1		)
Basis
- Natural gas (Bcf)	Swaps	—		(56.3		)	—		(31.7		)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	$	—		$	400.0	$	—

Cash Flow Hedges - At March 31, 2013, our Consolidated Balance Sheet reflected a net unrealized loss of $112.6 million in accumulated other comprehensive income (loss). The portion of accumulated other comprehensive income (loss) attributable to our commodity derivative instruments is a loss of $7.2 million, which will be realized within the next 33 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $6.7 million in losses over the next 12 months, and we will recognize $0.5 million in losses thereafter. The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $122.0 million, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $10.4 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive income (loss) are attributable primarily to forward-starting interest-rate swaps with settlement dates greater than 12 months, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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



	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
Derivatives in Cash Flow Hedging Relationships	2013			2012
	(Thousands of dollars)
Commodity contracts	$	(19,768	)	$	15,990
Interest-rate contracts	6,788			14,036
Total unrealized gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(12,980	)	$	30,026

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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 Loss into Net Income (Effective Portion)	Three Months Ended
		March 31,
		2013			2012
		(Thousands of dollars)
Commodity contracts	Revenues	$	2,566		$	6,698
Interest-rate contracts	Interest expense	(2,305		)	(92		)
Total gain (loss) reclassified from accumulated other comprehensive loss into net income (effective portion)		$	261		$	6,606

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2013 and 2012. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2013 and 2012.

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 $3.8 million at March 31, 2013, and $15.1 million at December 31, 2012, 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 Credit Agreement - Our Partnership 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 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 Credit Agreement, amounts outstanding under our Partnership Credit Agreement, if any, may become due and payable immediately. At March 31, 2013, our ratio of indebtedness to adjusted EBITDA was 3.3 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Our Partnership 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 Credit Agreement is available for general partnership purposes, including repayment of our commercial paper notes, if necessary. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement. At March 31, 2013, we had no commercial paper outstanding, no letters of credit issued and no borrowings under our Partnership Credit Agreement.

Our Partnership Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points based on our current credit rating. Our Partnership Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under our Partnership Credit Agreement are nonrecourse to ONEOK.


E.	EQUITY

ONEOK - ONEOK and its affiliates own all of the Class B units, 19.8 million common units and the entire 2-percent general partner interest in us, which together constituted a 43.3-percent ownership interest in us at March 31, 2013.

Equity Issuances - We have an “at-the-market” equity program for the offer and sale from time to time of our common units up to an aggregate amount of $300 million. The program allows us to offer and sell our common units at prices we deem

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appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program.

During the three months ended March 31, 2013, we sold common units through this program that resulted in net proceeds, including ONEOK’s contribution to maintain its 2-percent general partner interest, of approximately $16.5 million, which includes $3.4 million received in April 2013. We used the proceeds for general partnership purposes. As a result of these transactions, ONEOK’s aggregate ownership interest in us decreased to 43.3 percent at March 31, 2013, from 43.4 percent at December 31, 2012.

In March 2012, we completed an underwritten public offering of 8.0 million common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million. We also sold 8.0 million 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. 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.

Partnership Agreement - Available cash, as defined in our Partnership Agreement, generally will 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.

Cash Distributions - In April 2013, our general partner declared a cash distribution of $0.715 per unit ($2.86 per unit on an annualized basis) for the first quarter of 2013, an increase of 0.5 cents from the previous quarter, which will be paid on May 15, 2013, to unitholders of record at the close of business on April 30, 2013.

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



	Three Months Ended
	March 31,
	2013		2012
	(Thousands, except per unit amounts)
Distribution per unit	$	0.71	$	0.61

General partner distributions	$	4,418	$	3,281
Incentive distributions	60,437		36,472
Distributions to general partner	64,855		39,753
Limited partner distributions to ONEOK	65,880		51,721
Limited partner distributions to other unitholders	90,189		72,609
Total distributions paid	$	220,924	$	164,083

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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
	March 31,
	2013		2012
	(Thousands, except per unit amounts)
Distribution per unit	$	0.715	$	0.635

General partner distributions	$	4,469	$	3,759
Incentive distributions	61,576		44,610
Distributions to general partner	66,045		48,369
Limited partner distributions to ONEOK	66,344		58,921
Limited partner distributions to other unitholders	91,039		80,662
Total distributions declared	$	223,428	$	187,952


F.	ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period indicated:



	Accumulated Other Comprehensive Loss (a)
	(Thousands of dollars)
January 1, 2013	$	(99,322	)
Other comprehensive income (loss) before reclassifications	(12,980		)
Amounts reclassified from accumulated other comprehensive income (loss)
Commodity contracts (b)	(2,566		)
Interest-rate contracts (c)	2,305
Total	(261		)
Net current-period other comprehensive income (loss) attributable to ONEOK Partners	(13,241		)
March 31, 2013	$	(112,563	)

(a) All amounts are attributable to unrealized gains (losses) in risk-management assets/liabilities.

(b) Included in revenue in consolidated statement of income.


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
	March 31,
	2013		2012
	(Thousands of dollars)
Northern Border Pipeline	$	16,390	$	20,231
Overland Pass Pipeline Company	2,899		5,317
Fort Union Gas Gathering	3,869		4,208
Bighorn Gas Gathering	712		1,165
Other	1,985		3,699
Equity earnings from investments	$	25,855	$	34,620

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



	Three Months Ended
	March 31,
	2013		2012
	(Thousands of dollars)
Income Statement
Operating revenues	$	127,801	$	127,924
Operating expenses	$	64,271	$	54,568
Net income	$	58,204	$	65,254

Distributions paid to us	$	30,193	$	40,941

We incurred expenses in transactions with unconsolidated affiliates of $7.8 million and $9.4 million, which are included in cost of sales and fuel in our Consolidated Statements of Income, for the three months ended March 31, 2013 and 2012, respectively, primarily related to Overland Pass Pipeline Company. Accounts payable to our equity method investees at March 31, 2013, and December 31, 2012 were not material.

In January 2013, the FERC approved a settlement between Northern Border Pipeline and its customers that modified its transportation rates, effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower compared with previous rates, which reduced our equity earnings in the first quarter 2013 and are expected to reduce equity earnings and cash distributions from Northern Border Pipeline in the future.


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 and ONEOK Partners GP (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 Gas 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.

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ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees; however, an expense benefiting the consolidated

company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that includes gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

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

The following table sets forth the transactions with related parties for the periods indicated:



	Three Months Ended
	March 31,
	2013		2012
	(Thousands of dollars)
Revenues	$	82,634	$	75,705

Expenses
Cost of sales and fuel	$	9,551	$	9,275
Administrative and general expenses	72,496		56,361
Total expenses	$	82,047	$	65,636

ONEOK Partners GP made additional general partner contributions to us of approximately $0.3 million during the three months ended March 31, 2013, and $19.1 million during the three months ended March 31, 2012, to maintain its 2-percent general partner interest in connection with the issuance of common units. See Note E 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 preservation, wildlife preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or 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. For example, 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 and/or other regulatory or permitting mandates 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 statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or 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 assessment, 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 months ended March 31, 2013 and 2012.

The EPA’s “Tailoring Rule” 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. At current emission threshold levels, this rule 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,

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which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

The EPA’s rule on air-quality standards, titled “National Emissions Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also know as RICE NESHAP, initially included a compliance date in 2013. Subsequent industry appeals and settlements with the EPA have extended timelines associated with the final RICE NESHAP rule. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

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 natural gas industry, including natural gas production, processing, transmission and underground storage sectors. 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. In March 2013, the EPA issued proposed rulemaking to amend the NSPS for the crude oil and natural gas industry, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule. Beyond the March 2013 proposed amendments, the EPA has indicated it may provide additional responses, amendments and/or policy guidance to amend or clarify other portions of the final rule in 2013. Based on the currently proposed rulemaking amendments and our understanding of pending stakeholder responses to the NSPS rule, we anticipate that if the EPA issues additional responses, amendments and/or policy guidance on the final rule, it will reduce our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. Generally, the NSPS final rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude-oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to PHMSA 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 law increased 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 the following:


•	an evaluation on 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 liquids 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 previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

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 most of the provisions of the Dodd-Frank Act. In April 2013, CFTC took action that extends the compliance deadlines for certain reporting requirements applicable to us, the earliest of which is July 1, 2013. Based on our assessment of the regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity-price 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 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.

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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 cash flows.


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 - We evaluate performance based principally on each segment’s operating income and equity earnings. 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, natural gas producers 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 natural gas production companies, propane distributors, ethanol producers and petrochemical, refining and NGL marketing companies.

For the three months ended March 31, 2013, we had no single customer from which we received 10 percent or more of our consolidated revenues. For the three months ended March 31, 2012, our Natural Gas Liquids segment had one customer from which we received 10 percent of our consolidated revenues.

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



Three Months Ended March 31, 2013	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)			Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	137,245	$	59,325		$	2,238,243	$	—		$	2,434,813
Sales to affiliated customers	55,658		26,976			—		—			82,634
Intersegment revenues	244,611		(272		)	26,425		(270,764		)	—
Total revenues	$	437,514	$	86,029		$	2,264,668	$	(270,764	)	$	2,517,447

Net margin	$	109,285	$	74,072		$	186,620	$	622		$	370,599
Operating costs	51,688		27,166			59,802		(392		)	138,264
Depreciation and amortization	23,904		11,036			19,738		—			54,678
Gain on sale of assets	28		4			9		—			41
Operating income	$	33,721	$	35,874		$	107,089	$	1,014		$	177,698

Equity earnings from investments	$	6,331	$	16,389		$	3,135	$	—		$	25,855
Investments in unconsolidated affiliates	$	335,140	$	388,189		$	496,800	$	—		$	1,220,129
Total assets	$	3,146,236	$	1,799,121		$	5,647,351	$	103,299		$	10,696,007
Noncontrolling interests in consolidated subsidiaries	$	4,691	$	—		$	—	$	15		$	4,706
Capital expenditures	$	163,948	$	5,342		$	274,165	$	9		$	443,464

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.4 million, net margin of $57.7 million and operating income of $23.8 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $108.2 million, of which $84.6 million related to sales within the segment, net margin of $61.5 million and operating income of $31.3 million.



Three Months Ended March 31, 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	$	98,695	$	52,742	$	2,366,946	$	—		$	2,518,383
Sales to affiliated customers	52,684		23,021		—		—			75,705
Intersegment revenues	215,400		847		15,984		(232,231		)	—
Total revenues	$	366,779	$	76,610	$	2,382,930	$	(232,231	)	$	2,594,088

Net margin	$	108,327	$	70,603	$	243,753	$	(1,593	)	$	421,090
Operating costs	40,262		26,175		51,947		(2,514		)	115,870
Depreciation and amortization	20,516		11,413		17,327		—			49,256
Gain on sale of assets	26		—		31		—			57
Operating income	$	47,575	$	33,015	$	174,510	$	921		$	256,021

Equity earnings from investments	$	8,488	$	20,386	$	5,746	$	—		$	34,620
Investments in unconsolidated affiliates	$	327,393	$	418,788	$	473,454	$	—		$	1,219,635
Total assets	$	2,550,181	$	1,875,683	$	4,630,222	$	751,103		$	9,807,189
Noncontrolling interests in consolidated subsidiaries	$	—	$	5,047	$	—	$	(59	)	$	4,988
Capital expenditures	$	124,873	$	3,226	$	152,614	$	80		$	280,793

(a) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $60.6 million, net margin of $55.0 million and operating income of $23.1 million.

(b) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $110.6 million, of which $92.1 million related to sales within the segment, net margin of $67.9 million and operating income of $41.5 million.

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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. 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. We have recast prior-period amounts in the condensed consolidating statements of cash flows to revise the classification of dividends received by the Parent from the Guarantor Subsidiary from financing to operating activities.

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Condensed Consolidating Statements of Income



	Three Months Ended March 31, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—		$	2,517.4		$	—		$	2,517.4
Cost of sales and fuel	—			—			2,146.8			—			2,146.8
Net margin	—			—			370.6			—			370.6
Operating expenses
Operations and maintenance	—			—			121.3			—			121.3
Depreciation and amortization	—			—			54.7			—			54.7
General taxes	—			—			17.0			—			17.0
Total operating expenses	—			—			193.0			—			193.0
Gain on sale of assets	—			—			0.1			—			0.1
Operating income	—			—			177.7			—			177.7
Equity earnings from investments	156.6			156.6			9.5			(296.8		)	25.9
Allowance for equity funds used during construction	—			—			9.1			—			9.1
Other income (expense), net	67.0			67.0			2.2			(134.0		)	2.2
Interest expense	(67.0		)	(67.0		)	(55.9		)	134.0			(55.9		)
Income before income taxes	156.6			156.6			142.6			(296.8		)	159.0
Income taxes	—			—			(2.3		)	—			(2.3		)
Net income	156.6			156.6			140.3			(296.8		)	156.7
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	156.6		$	156.6		$	140.2		$	(296.8	)	$	156.6



	Three Months Ended March 31, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues	$	—		$	—		$	2,594.1		$	—		$	2,594.1
Cost of sales and fuel	—			—			2,173.0			—			2,173.0
Net margin	—			—			421.1			—			421.1
Operating expenses
Operations and maintenance	—			—			100.4			—			100.4
Depreciation and amortization	—			—			49.3			—			49.3
General taxes	—			—			15.5			—			15.5
Total operating expenses	—			—			165.2			—			165.2
Gain on sale of assets	—			—			0.1			—			0.1
Operating income	—			—			256.0			—			256.0
Equity earnings from investments	238.8			238.8			14.4			(457.4		)	34.6
Allowance for equity funds used during construction	—			—			1.0			—			1.0
Other income (expense), net	51.5			51.5			4.2			(103.0		)	4.2
Interest expense	(51.5		)	(51.5		)	(53.2		)	103.0			(53.2		)
Income before income taxes	238.8			238.8			222.4			(457.4		)	242.6
Income taxes	—			—			(3.6		)	—			(3.6		)
Net income	238.8			238.8			218.8			(457.4		)	239.0
Less: Net income attributable to noncontrolling interests	—			—			0.2			—			0.2
Net income attributable to ONEOK Partners, L.P.	$	238.8		$	238.8		$	218.6		$	(457.4	)	$	238.8

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Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended March 31, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	156.6		$	156.6		$	140.3		$	(296.8	)	$	156.7
Other comprehensive income (loss)
Unrealized losses on derivatives	(13.0		)	(19.8		)	(19.8		)	39.6			(13.0		)
Realized gains on derivatives recognized in net income	(0.2		)	(2.6		)	(2.6		)	5.2			(0.2		)
Total other comprehensive loss	(13.2		)	(22.4		)	(22.4		)	44.8			(13.2		)
Comprehensive income	143.4			134.2			117.9			(252.0		)	143.5
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	143.4		$	134.2		$	117.8		$	(252.0	)	$	143.4



	Three Months Ended March 31, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	238.8		$	238.8		$	218.8		$	(457.4	)	$	239.0
Other comprehensive income (loss)
Unrealized gains on derivatives	30.0			16.0			16.0			(32.0		)	30.0
Realized gains on derivatives recognized in net income	(6.6		)	(6.6		)	(6.6		)	13.2			(6.6		)
Total other comprehensive income	23.4			9.4			9.4			(18.8		)	23.4
Comprehensive income	262.2			248.2			228.2			(476.2		)	262.4
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	262.2		$	248.2		$	228.1		$	(476.2	)	$	262.3

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Condensed Consolidating Balance Sheets



	March 31, 2013
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	68.9	$	—	$	—		$	68.9
Accounts receivable, net	—		—		778.4		—			778.4
Affiliate receivables	—		—		22.0		—			22.0
Gas and natural gas liquids in storage	—		—		228.8		—			228.8
Commodity imbalances	—		—		75.3		—			75.3
Other current assets	—		—		69.7		—			69.7
Total current assets	—		68.9		1,174.2		—			1,243.1
Property, plant and equipment
Property, plant and equipment	—		—		9,008.7		—			9,008.7
Accumulated depreciation and amortization	—		—		1,490.4		—			1,490.4
Net property, plant and equipment	—		—		7,518.3		—			7,518.3
Investments and other assets
Investments in unconsolidated affiliates	4,372.0		3,971.5		832.6		(7,956.0		)	1,220.1
Intercompany notes receivable	4,801.5		5,133.1		—		(9,934.6		)	—
Goodwill and intangible assets	—		—		644.0		—			644.0
Other assets	48.4		—		22.1		—			70.5
Total investments and other assets	9,221.9		9,104.6		1,498.7		(17,890.6		)	1,934.6
Total assets	$	9,221.9	$	9,173.5	$	10,191.2	$	(17,890.6	)	$	10,696.0
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.7	$	—		$	7.7
Accounts payable	—		—		971.2		—			971.2
Affiliate payables	—		—		45.3		—			45.3
Commodity imbalances	—		—		202.2		—			202.2
Accrued interest	87.5		—		—		—			87.5
Other current liabilities	—		—		67.9		—			67.9
Total current liabilities	87.5		—		1,294.3		—			1,381.8
Intercompany debt	—		4,801.5		5,133.1		(9,934.6		)	—
Long-term debt, excluding current maturities	4,736.7		—		65.3		—			4,802.0
Deferred credits and other liabilities	—		—		109.8		—			109.8
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	4,397.7		4,372.0		3,584.0		(7,956.0		)	4,397.7
Noncontrolling interests in consolidated subsidiaries	—		—		4.7		—			4.7
Total equity	4,397.7		4,372.0		3,588.7		(7,956.0		)	4,402.4
Total liabilities and equity	$	9,221.9	$	9,173.5	$	10,191.2	$	(17,890.6	)	$	10,696.0

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	December 31, 2012
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	537.1	$	—	$	—		$	537.1
Accounts receivable, net	—		—		914.0		—			914.0
Affiliate receivables	—		—		16.1		—			16.1
Gas and natural gas liquids in storage	—		—		235.8		—			235.8
Commodity imbalances	—		—		89.7		—			89.7
Other current assets	10.9		—		88.1		—			99.0
Total current assets	10.9		537.1		1,343.7		—			1,891.7
Property, plant and equipment
Property, plant and equipment	—		—		8,585.2		—			8,585.2
Accumulated depreciation and amortization	—		—		1,440.9		—			1,440.9
Net property, plant and equipment	—		—		7,144.3		—			7,144.3
Investments and other assets
Investments in unconsolidated affiliates	4,458.7		3,858.9		828.6		(7,924.8		)	1,221.4
Intercompany notes receivable	4,770.6		4,833.3		—		(9,603.9		)	—
Goodwill and intangible assets	—		—		645.8		—			645.8
Other assets	31.6		—		24.4		—			56.0
Total investments and other assets	9,260.9		8,692.2		1,498.8		(17,528.7		)	1,923.2
Total assets	$	9,271.8	$	9,229.3	$	9,986.8	$	(17,528.7	)	$	10,959.2
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.6	$	—		$	7.6
Accounts payable	—		—		1,058.0		—			1,058.0
Affiliate payables	—		—		75.7		—			75.7
Commodity imbalances	—		—		273.2		—			273.2
Accrued interest	76.7		—		—		—			76.7
Other current liabilities	—		—		79.2		—			79.2
Total current liabilities	76.7		—		1,493.7		—			1,570.4
Intercompany debt	—		4,770.6		4,833.3		(9,603.9		)	—
Long-term debt, excluding current maturities	4,736.4		—		67.2		—			4,803.6
Deferred credits and other liabilities	—		—		121.7		—			121.7
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	4,458.7		4,458.7		3,466.1		(7,924.8		)	4,458.7
Noncontrolling interests in consolidated subsidiaries	—		—		4.8		—			4.8
Total equity	4,458.7		4,458.7		3,470.9		(7,924.8		)	4,463.5
Total liabilities and equity	$	9,271.8	$	9,229.3	$	9,986.8	$	(17,528.7	)	$	10,959.2

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Condensed Consolidating Statements of Cash Flows



	Three Months Ended March 31, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	225.7		$	16.4		$	160.2		$	(220.9	)	$	181.4
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(443.5		)	—			(443.5		)
Contributions to unconsolidated affiliates	—			—			(3.0		)	—			(3.0		)
Distributions received from unconsolidated affiliates	—			5.1			1.6			—			6.7
Proceeds from sale of assets	—			—			—			—			—
Cash provided by (used in) investing activities	—			5.1			(444.9		)	—			(439.8		)
Financing activities
Cash distributions:
General and limited partners	(220.9		)	(220.9		)	—			220.9			(220.9		)
Noncontrolling interests	—			—			(0.1		)	—			(0.1		)
Intercompany borrowings (advances), net	(17.9		)	(268.8		)	286.7			—			—
Repayment of long-term debt	—			—			(1.9		)	—			(1.9		)
Issuance of common units, net of issuance costs	12.8			—			—			—			12.8
Contribution from general partner	0.3			—			—			—			0.3
Cash provided by (used in) financing activities	(225.7		)	(489.7		)	284.7			220.9			(209.8		)
Change in cash and cash equivalents	—			(468.2		)	—			—			(468.2		)
Cash and cash equivalents at beginning of period	—			537.1			—			—			537.1
Cash and cash equivalents at end of period	$	—		$	68.9		$	—		$	—		$	68.9

Table of Contents



	Three Months Ended March 31, 2012
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	164.1		$	20.2		$	199.0		$	(164.1	)	$	219.2
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(280.8		)	—			(280.8		)
Contributions to unconsolidated affiliates	—			—			(2.6		)	—			(2.6		)
Distributions received from unconsolidated affiliates	—			4.1			—			—			4.1
Proceeds from sale of assets	—			—			0.4			—			0.4
Cash provided by (used in) investing activities	—			4.1			(283.0		)	—			(278.9		)
Financing activities
Cash distributions:
General and limited partners	(164.1		)	(164.1		)	—			164.1			(164.1		)
Noncontrolling interests	—			—			(0.2		)	—			(0.2		)
Intercompany borrowings (advances), net	(938.6		)	851.4			87.2			—			—
Repayment of long-term debt	—			—			(3.0		)	—			(3.0		)
Issuance of common units, net of issuance costs	919.5			—			—			—			919.5
Contribution from general partner	19.1			—			—			—			19.1
Cash provided by (used in) financing activities	(164.1		)	687.3			84.0			164.1			771.3
Change in cash and cash equivalents	—			711.6			—			—			711.6
Cash and cash equivalents at beginning of period	—			35.1			—			—			35.1
Cash and cash equivalents at end of period	$	—		$	746.7		$	—		$	—		$	746.7

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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

Market Conditions - Natural gas and natural gas liquids supply continues to increase, caused by the drilling activities in crude oil and NGL-rich resource areas. While natural gas prices increased modestly in the first quarter 2013, compared with the same period last year, these drilling activities have resulted in lower NGL prices, minimal natural gas price volatility and narrower natural gas location and seasonal price differentials in the markets we serve. In addition, we realized in the first quarter 2013 significantly lower NGL price differentials between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, compared with the same period last year. The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and natural gas, may influence the volume of ethane and propane natural gas processing plants will make available to be gathered in our Natural Gas Liquids segment. 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 natural gas stream sold at the tailgate of natural gas processing plants. Price differentials between ethane and natural gas resulted in ethane rejection at some of our natural gas processing plants and some of our customers’ natural gas processing plants connected to our system in the Mid-Continent and Rocky Mountain regions during the first quarter 2013, which reduced natural gas liquids volumes transported and fractionated in our Natural Gas Liquids segment and our results of operations. Widespread and prolonged ethane rejection in 2013 is expected to have a significant impact on our financial results. While there may be periods of ethane rejection in 2014, we do not expect them be widespread and prolonged. See additional discussion in the “Financial Results and Operating Information” section in our Natural Gas Liquids segment.

Despite lower commodity prices, North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from nonconventional resource areas such as shales. Producers currently receive higher market prices on a heating-value basis for crude oil and composite NGLs compared with natural gas. As a result, many producers focused their drilling activity in shale areas that produce crude oil and NGL-rich natural gas rather than in areas with dry natural gas production. We expect continued demand for midstream infrastructure development, driven by producers who need to connect emerging production with end-use markets where current infrastructure is insufficient or nonexistent.

Growth Projects - Crude-oil and natural gas producers continue to drill aggressively for crude oil and NGL-rich natural gas, and related development activities continue to progress in many regions where we have operations. We expect continued development of the crude-oil and NGL-rich 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 $4.7 billion to $5.2 billion in new capital projects between 2011 and 2015 to meet the needs of natural gas producers and processors in the these regions, as well as enhancing our natural gas liquids distribution infrastructure in the Gulf Coast region. 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.

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						Variances
	March 31,						2013 vs. 2012
Financial Results	2013			2012			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,517.4		$	2,594.1		$	(76.7	)	(3	%)
Cost of sales and fuel	2,146.8			2,173.0			(26.2		)	(1	%)
Net margin	370.6			421.1			(50.5		)	(12	%)
Operating costs	138.3			115.9			22.4			19	%
Depreciation and amortization	54.7			49.3			5.4			11	%
Gain on sale of assets	0.1			0.1			—			—	%
Operating income	$	177.7		$	256.0		$	(78.3	)	(31	%)

Equity earnings from investments	$	25.9		$	34.6		$	(8.7	)	(25	%)
Interest expense	$	(55.9	)	$	(53.2	)	$	2.7		5	%
Capital expenditures	$	443.5		$	280.8		$	162.7		58	%

Revenues decreased for the three months ended March 31, 2013, compared with the same period last year, due to lower realized natural gas and NGL product prices, significantly narrower NGL price differentials between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, and the impact of ethane rejection in our Natural Gas Liquids segment, offset partially by higher natural gas and NGL volumes from our recently completed capital projects. The increase in natural gas and NGL supply resulting from the development of nonconventional resource areas in North America has caused narrower natural gas location and seasonal price differentials in the markets we serve and lower NGL prices during the three months ended March 31, 2013, compared with the same period last year.

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. Lower ethane prices have resulted in ethane rejection at some of our natural gas processing plants and some of our customers’ natural gas processing plants connected to our natural gas liquids system in the Mid-Continent and Rocky Mountain regions during the first quarter 2013.

The decrease in operating income for the three-month period reflects lower net margin resulting from narrower NGL location price differentials, lower net realized natural gas and NGL product prices and the impact of ethane rejection offset partially by higher volumes in the Natural Gas Gathering and Processing and Natural Gas Liquids segments from our recently completed capital projects. Operating costs and depreciation and amortization increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the growth of our operations related to our completed capital projects. Equity earnings from investments decreased due to the impact of ethane rejection on Overland Pass Pipeline Company and decreased transportation rates on Northern Border Pipeline.

Interest expense increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to interest costs from our $1.3 billion debt issuance in September 2012, offset partially by capitalized interest associated with investments in our growth projects.

Capital expenditures increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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

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Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides 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, Granite Wash area and 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 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 2 percent of our contracted volumes, allow us to retain the NGLs as our fee for service and return to the producer an equivalent quantity, on a Btu basis, of residue gas.

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 sensitivity 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 $2.1 billion to $2.2 billion through 2015 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 - Our projects in this basin include five 100 MMcf/d natural gas processing facilities: the Garden Creek, Garden Creek II and Garden Creek III 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 3.1 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. We expect construction costs, excluding AFUDC, for the Garden Creek II plant and related infrastructure will be $310 million to $345 million, and for the Garden Creek III plant and related infrastructure will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be completed during the third quarter 2014 and the first quarter 2015, respectively. The Stateline I natural gas processing facility was placed into service in September 2012, and the Stateline II natural gas processing facility was placed in service April 2013. Together with the related infrastructure, the Stateline I and II plants are expected to cost approximately $590 million to $610 million, excluding AFUDC.

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 our Stateline natural gas processing facilities in western Williams County, North Dakota. We have secured long-term acreage dedications from producers for this new system, which are structured with POP and fee-based contractual components. We have completed construction on approximately 50 percent of the infrastructure and expect it to be completed in the third quarter 2013.

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 and natural gas liquids 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

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approximately $190 million, excluding AFUDC, and is expected to be completed 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. 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 historical levels of routine growth capital.

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				Variances
	March 31,				2013 vs. 2012
Financial Results	2013		2012		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	260.4	$	238.7	$	21.7		9	%
Residue gas sales	127.5		86.0		41.5			48	%
Gathering, compression, dehydration and processing fees and other revenue	49.6		42.1		7.5			18	%
Cost of sales and fuel	328.2		258.5		69.7			27	%
Net margin	109.3		108.3		1.0			1	%
Operating costs	51.7		40.2		11.5			29	%
Depreciation and amortization	23.9		20.5		3.4			17	%
Operating income	$	33.7	$	47.6	$	(13.9	)	(29	%)

Equity earnings from investments	$	6.3	$	8.5	$	(2.2	)	(26	%)
Capital expenditures	$	163.9	$	124.9	$	39.0		31	%

Net margin remained relatively unchanged for the three months ended March 31, 2013, compared with the same period last year, primarily as a result of the following:


•	an increase of $28.2 million due primarily to volume growth in the Williston Basin from our new Stateline I 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 $13.0 million due primarily to lower net realized NGL product prices;


•	a decrease of $13.0 million due primarily to higher compression costs and less favorable contract terms associated with our volume growth primarily in the Williston Basin; and


•	a decrease of $1.3 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 March 31, 2013, compared with the same period last year, primarily as a result of the growth of our operations, which reflects the operations of our Stateline I natural gas processing plant that was placed in service in September 2012 and the start-up costs associated with our Stateline II natural gas processing plant, including the following:


•	an increase of $5.6 million from higher materials and supplies, and outside services expenses;


•	an increase of $4.2 million due to higher labor and employee-related costs; and


•	an increase of $1.3 million due to higher ad valorem taxes.

Depreciation and amortization expense increased for the three months ended March 31, 2013, compared with the same period last year, due to the completion of our Stateline I natural gas processing plant, well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased for the three months ended March 31, 2013, 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

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Williston Basin. During the first quarter 2013, we connected approximately 270 new wells to our systems, despite periods of challenging winter snow conditions in North Dakota, compared with approximately 200 in the same period last year.

Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information (a)	2013		2012
Natural gas gathered (BBtu/d)	1,215		1,045
Natural gas processed (BBtu/d) (b)	989		769
NGL sales (MBbl/d)	72		53
Residue gas sales (BBtu/d)	436		357
Realized composite NGL net sales price ($/gallon) (c)	$	0.85	$	1.09
Realized condensate net sales price ($/Bbl) (c)	$	88.28	$	89.89
Realized residue gas net sales price ($/MMBtu) (c)	$	3.57	$	3.71

(a) - Includes volumes for consolidated entities only.

(b) - Includes volumes processed at company-owned and third-party facilities.

Volumes increased for the three months ended March 31, 2013, compared with the same period 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 Stateline I natural gas processing plant that was placed in service in September 2012, 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 crude oil and NGL prices compared with natural gas on a heating-value basis 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 natural gas volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. Bighorn Gas Gathering, in which we own a 49-percent equity interest, operates in the Powder River Basin. Due to recent changes in producer activity and declines in volumes gathered on the Bighorn Gas Gathering system, we tested our investment for impairment. The carrying amount of our investment at March 31, 2013, was $90.0 million, which includes $53.4 million in equity method goodwill. We estimated the fair value of our investment in Bighorn Gas Gathering using an income approach, which discounted the estimated future cash flows of our investment’s underlying assets with a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures. The fair value exceeded the carrying value; therefore, no impairment was recorded.

A decline of 10 percent or more in the fair value of our investment in Bighorn Gas Gathering would result in a noncash impairment charge. For our other equity-method investments with operations in the Powder River Basin with carrying values of approximately $200 million, which includes approximately $130 million in equity method goodwill, we did not identify current events or circumstances that warranted an impairment analysis or adjustment to our carrying values. We are not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in a fair value model are dependent upon events such as changes in commodity prices, producers’ drilling and production activity and effects of government regulations and policies.

Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

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 have the capability to recover ethane when economic conditions warrant but did not recover ethane during the first quarter. As a result, our first-quarter equity NGL volumes are weighted more toward propane, iso-butane, normal butane and natural gasoline compared with last year.

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	Three Months Ended
	March 31,
Operating Information (a) (d)	2013			2012
Commodity
NGL sales (Bbl/d) (b)	12,008			9,699
Residue gas sales (MMBtu/d) (c)	56,361			41,196
Condensate sales (Bbl/d) (b)	2,632			2,743
Percentage of total net margin	64		%	69		%
Fee-based
Wellhead volumes (MMBtu/d)	1,214,789			1,044,641
Average rate ($/MMBtu)	$	0.36		$	0.36
Percentage of total net margin	36		%	31		%

(a) - Includes volumes for consolidated entities only.

(b) - Represents equity volumes.

(d) - Keep-whole quantities represent less than two percent of our contracts by volume. The quantities of natural gas for fuel and shrink associated with our keep-whole contacts have been deducted from residue gas sales, and the NGLs and condensate retained from our keep-whole contacts are included in NGL sales and condensate sales. Prior periods have been recast to conform to current presentation.

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 at March 31, 2013:



	Nine Months Ending December 31, 2013
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d)	9,409	$	1.05	/ gallon	64%
Condensate (Bbl/d)	2,028	$	2.43	/ gallon	83%
Total (Bbl/d)	11,437	$	1.29	/ gallon	67%
Natural gas (MMBtu/d)	64,036	$	3.79	/ MMBtu	78%



	Year Ending December 31, 2014
	Volumes Hedged	Average Price			Percentage Hedged
Condensate (Bbl/d)	868	$	2.22	/ gallon	33%
Natural gas (MMBtu/d)	69,274	$	4.11	/ MMBtu	91%



	Year Ending December 31, 2015
	Volumes Hedged	Average Price			Percentage Hedged
Natural gas (MMBtu/d)	48,877	$	4.19	/ MMBtu	50%

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 March 31, 2013, 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 $2.5 million;


•	a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.1 million; and


•	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.9 million.

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

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Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment owns and operates regulated natural gas transmission pipelines and natural gas storage facilities. We also provide interstate natural gas transportation and storage service 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 Corporation’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 Company, 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 area and Delaware and Cline producing areas in 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.

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 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				Variances
	March 31,				2013 vs. 2012
Financial Results	2013		2012		Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	60.5	$	56.8	$	3.7		7	%
Storage revenues	17.4		15.6		1.8			12	%
Gas sales and other revenues	8.1		4.2		3.9			93	%
Cost of sales	11.9		6.0		5.9			98	%
Net margin	74.1		70.6		3.5			5	%
Operating costs	27.2		26.2		1.0			4	%
Depreciation and amortization	11.0		11.4		(0.4		)	(4	%)
Operating income	$	35.9	$	33.0	$	2.9		9	%

Equity earnings from investments	$	16.4	$	20.4	$	(4.0	)	(20	%)
Capital expenditures	$	5.3	$	3.2	$	2.1		66	%

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Net margin increased for the three months ended March 31, 2013, compared with the same period last year, primarily as a result of the following:


•	an increase of $1.6 million as a result of higher rates on Guardian Pipeline;


•	an increase of $1.3 million due to higher contracted capacity with natural gas producers on our intrastate pipelines; and


•	an increase of $1.2 million from higher natural gas storage margins primarily as a result of higher negotiated rates.

Equity earnings from our investments decreased due primarily to reduced transportation rates resulting from a Northern Border Pipeline rate settlement, effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower compared with previous rates, which reduced our equity earnings in the first quarter 2013 and are expected to reduce equity earnings and cash distributions from Northern Border Pipeline in the future. Substantially all of Northern Border Pipeline’s long-haul transportation capacity has been contracted through March 2014.



	Three Months Ended
	March 31,
Operating Information (a)	2013			2012
Natural gas transportation capacity contracted (MDth/d)	5,670			5,552
Transportation capacity subscribed (b)	93		%	92		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	3.42		$	2.37

(a) - Includes volumes for consolidated entities only.

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

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 and other 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 developed, we expect producers to demand incremental services in the future to transport their production to market. 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. Conversely, contracted capacity by certain customers that are focused on capturing location or seasonal price differentials may decrease in the future due to narrowing price differentials. Overall, we expect our fee-based earnings to remain relatively stable in the future as the development of shale and other resource areas continues.

In November 2012, the FERC initiated a review of Viking Gas Transmission’s rates pursuant to Section 5 of the Natural Gas Act. The review is currently in process, and while the ultimate outcome cannot be predicted, it could result in a future reduction of rates. We do not expect the ultimate outcome to impact materially our results of operations.

Natural Gas Liquids

Overview - Our natural gas liquids segment owns and operates 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, Montana, North Dakota 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 unfractionated 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. In March 2013, we began transporting unfractionated NGLs from the Williston Basin into our completed Bakken NGL Pipeline. These unfractionated NGLs previously were transported by rail to our Mid-Continent natural gas liquids fractionation facilities. We will continue to use these rail terminal facilities in our NGL marketing activities.

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 nondiscretionary fee-based services provided to our customers and from the 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 utilize our assets to gather, fractionate and treat unfractionated NGLs for a fee, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments.

•

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 Conway, Kansas, and Mont Belvieu, Texas, in order to capture the location price differentials between the two market centers. Our natural gas liquids storage facilities are also utilized to capture seasonal price variances. A growing portion of our marketing activities serves truck and rail markets.


•	Our pipeline transportation services transport unfractionated NGLs, NGL products and refined petroleum products, primarily under our FERC-regulated tariffs. Tariffs specify the maximum rates we charge our customers and the general terms and conditions for NGL transportation service on our pipelines.


•	Our isomerization activities capture 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 activities store NGLs at our Mid-Continent and Gulf Coast facilities for a fee.

Growth Projects - Our growth strategy in the Natural Gas Liquids segment is focused around the crude 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 in the next three to five years, and international demand for propane is impacting positively the NGL markets now and is expected to in the future. Our Natural Gas Liquids segment is investing approximately $2.6 billion to $3.0 billion in NGL-related projects through 2015. These investments will accommodate the transportation and fractionation of growing NGL supply from shale and other resource development areas across our asset base and alleviate infrastructure constraints between the Mid-Continent and Gulf Coast market centers to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. Over time, these growing fee-based NGL volumes are expected to fill much of our natural gas liquids pipeline capacity used historically to capture the NGL price differentials between the two market centers. During the second half 2012 and through the first quarter 2013, NGL price differentials narrowed significantly between the Mid-Continent and Gulf Coast market centers. We expect these narrower NGL price differentials to continue as new fractionators and pipelines, including our growth projects discussed below, continue to alleviate constraints between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers.

Sterling III Pipeline - We are constructing a 540-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 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. The pipeline is expected to be completed late this year.

The project also includes reconfiguration of our existing Sterling I and II pipelines, which distribute NGL products between the Mid-Continent and Gulf Coast natural gas liquids market centers, to transport either unfractionated NGLs or NGL products. The project costs for the new pipeline and reconfiguration 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. Construction began in June 2011 and is expected to be completed in the third quarter 2013. The cost of the new

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fractionator is 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 - We also 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 natural gas liquids 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 Header Pipeline - In April 2013, we placed in service a 12-inch diameter ethane header pipeline that creates a new point of interconnection between our Mont Belvieu, Texas, NGL fractionation and storage assets and several petrochemical customers. The new pipeline has the capacity to transport 400 MBbl/d from our 80 percent-owned, 160 MBbl/d MB-1 fractionator and our 75 MBbl/d MB-2 and MB-3 fractionators that are currently under construction. The project cost approximately $23 million, excluding AFUDC.

Ethane/Propane Splitter - Additionally, 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 completed during the second quarter 2014. The ethane/propane splitter is expected to cost approximately $45 million, excluding AFUDC.

Bakken NGL Pipeline and related projects - The Bakken NGL Pipeline, a 600-mile natural gas liquids pipeline with the initial capacity to transport 60 MBbl/d of unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline, was placed in service in April 2013. The unfractionated NGLs then are delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from our natural gas processing plants.

We previously 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 the current capacity of 60 MBbl/d. Project costs for the new pipeline, including the expansion, are estimated to be $590 million to $620 million, excluding AFUDC. 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, which we expect to be completed in the second quarter 2013, 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 placed in service 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.

New NGL pipeline and modification of Hutchinson fractionation infrastructure - We plan to invest approximately $140 million, excluding AFUDC, to construct a new 95-mile natural gas liquids pipeline that will connect our existing natural gas liquids fractionation and storage facilities in Hutchinson, Kansas, to similar facilities in Medford, Oklahoma. These projects also include related modifications to existing natural gas liquids fractionation infrastructure at Hutchinson, Kansas, to accommodate additional unfractionated NGLs produced in the Williston Basin. The pipeline and related modifications are expected to be completed during the first quarter 2015.

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

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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.

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

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



	Three Months Ended				Variances
	March 31,				2013 vs. 2012
Financial Results	2013		2012		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,049.8	$	2,209.9	$	(160.1	)	(7	%)
Exchange service and storage revenues	192.4		155.4		37.0			24	%
Transportation revenues	22.5		17.6		4.9			28	%
Cost of sales and fuel	2,078.1		2,139.2		(61.1		)	(3	%)
Net margin	186.6		243.7		(57.1		)	(23	%)
Operating costs	59.8		51.9		7.9			15	%
Depreciation and amortization	19.7		17.3		2.4			14	%
Operating income	$	107.1	$	174.5	$	(67.4	)	(39	%)

Equity earnings from investments	$	3.1	$	5.7	$	(2.6	)	(46	%)
Capital expenditures	$	274.2	$	152.6	$	121.6		80	%

NGL prices decreased in the three months ended March 31, 2013, compared with the same period last year, due primarily to increased NGL production from the development of NGL-rich areas. NGL price differentials were significantly narrower between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, for the three months ended March 31, 2013, compared with the same period last year, due primarily to strong NGL production growth from the development of NGL-rich areas, higher levels of NGLs in storage at Mont Belvieu and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers as a result of ethane rejection in the Rocky Mountain and Mid-Continent regions.

Net margin decreased for the three months ended March 31, 2013, compared with the same period last year, primarily as a result of the following:

•

a decrease of $89.8 million in optimization and marketing margins, which resulted from a $92.5 million decrease due to significantly narrower NGL location price differentials and reduced 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 was utilized by our exchange services activities to produce fee-based earnings. This decrease was offset partially by a $2.6 million increase in our marketing activities; and


•	a decrease of $9.0 million resulting from the impact of ethane rejection during the first quarter 2013; offset partially by


•	an increase of $39.3 million related to the exchange services margins, which resulted from higher NGL volumes gathered in the Williston Basin, contract renegotiations for higher fees associated with our NGL exchange services activities and higher revenues from customers with minimum volume obligations; and


•	an increase of $2.8 million due to the impact of higher operational measurement gains.

Operating costs increased for the three months ended March 31, 2013, compared with the same period last year, primarily as a result of the following:


•	an increase of $4.4 million due to higher labor and employee-related costs associated with the growth of our operations related to our completed capital projects; and


•	an increase of $2.1 million from higher outside services expenses associated primarily with scheduled maintenance and the growth of our operations related to our completed capital projects.

Depreciation and amortization expense increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the depreciation associated with our completed capital projects.

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Equity earnings decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to $4.6 million in lower earnings from Overland Pass Pipeline Company in which we own a 50-percent interest, as a result of lower volumes due to ethane rejection, offset partially by lower operational measurement losses.

Capital expenditures increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to expenditures related to our growth projects discussed above.



	Three Months Ended
	March 31,
Operating Information	2013		2012
NGL sales (MBbl/d)	578		511
NGLs fractionated (MBbl/d) (a)	512		585
NGLs transported-gathering lines (MBbl/d) (b)	498		498
NGLs transported-distribution lines (MBbl/d) (b)	394		485
Conway-to-Mont Belvieu OPIS average price differential -
ethane in ethane/propane mix ($/gallon)	$	0.01	$	0.24

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

(b) - Includes volumes for consolidated entities only.

NGLs fractionated decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to ethane rejection during first quarter 2013.

NGLs transported on gathering lines were unchanged for the three months ended March 31, 2013, compared with the same period last year, due primarily to increased volumes of NGLs gathered as a result of the capacity increase in the Mid-Continent and Texas made available through our Cana-Woodford Shale and Granite Wash projects that were placed in service in April 2012, offset by decreases in NGL volumes gathered resulting from ethane rejection.

NGLs transported on distribution lines decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to decreased volumes resulting from ethane rejection.

CONTINGENCIES

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 three months of 2013, we utilized cash from operations and proceeds from equity sales under our “at-the-market” equity program to fund our short-term liquidity needs and our capital projects. See discussion 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.

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



	March 31,	December 31,
	2013	2012
Long-term debt	52%	52%
Equity	48%	48%
Debt (including notes payable)	52%	52%
Equity	48%	48%

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities and our commercial paper program.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At March 31, 2013, we had no commercial paper outstanding, no letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At March 31, 2013, we had approximately $68.9 million of cash and $1.2 billion of credit available under the Partnership Credit Agreement. At March 31, 2013, we could have issued $2.4 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 interest rates to increase in 2013, compared with interest rates on amounts outstanding during 2012.

Our Partnership 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 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 Credit Agreement, amounts outstanding under our Partnership Credit Agreement, if any, may become due and payable immediately. At March 31, 2013, our ratio of indebtedness to adjusted EBITDA was 3.3 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Events in the European economy could impact European banks. Various European-based banks participate in our Partnership 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 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 Credit Agreement.

Borrowings under our Partnership Credit Agreement and our senior notes are nonrecourse to ONEOK, and ONEOK does not guarantee our debt, commercial paper or other similar commitments.

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 leaseback of facilities.

We are subject to changes in the debt and equity markets, and there is no assurance we will be able or willing to access the public or private markets in the future. We may choose to meet our cash requirements by utilizing some combination of cash flows from operations, borrowing under our commercial paper program or our existing credit facility, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives. Some of these alternatives could involve higher costs or negatively affect our credit ratings, among other factors. Based on our investment-grade credit ratings, general financial condition and market expectations regarding our future earnings and projected cash flows, we believe that we will be able to meet our cash requirements and maintain our investment-grade credit ratings.

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Equity Issuance - We have an “at-the-market” equity program for the offer and sale from time to time of our common units up to an aggregate amount of $300 million. The program allows us to offer and sell our common units at prices we deem appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program.

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 March 31, 2013, and December 31, 2012, we had forward-starting interest-rate swaps with notional amounts totaling $400 million, which have settlement dates greater than 12 months.

Capital Expenditures - 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. Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity.

Capital expenditures were $443.5 million and $280.8 million for the three months ended March 31, 2013 and 2012, respectively.

The following table summarizes our 2013 projected growth and maintenance capital expenditures, excluding AFUDC:



	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	1,000	$	25	$	1,025
Natural Gas Pipelines	20		30		50
Natural Gas Liquids	1,500		60		1,560
Other	—		5		5
Total projected capital expenditures	$	2,520	$	120	$	2,640

Credit Ratings - Our long-term debt credit ratings at March 31, 2013, 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 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 Credit Agreement. An adverse rating change alone is not a default under our Partnership Credit Agreement. See additional discussion about our credit ratings under “Long-term Financing.”

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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.

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



	Three Months Ended
	March 31,
	2013		2012
	(Millions of dollars)
Common unitholders	$	104.2	$	79.8
Class B unitholders	51.8		44.5
General partner	64.9		39.8
Noncontrolling interests	0.2		0.2
Total cash distributions paid	$	221.1	$	164.3

In the three months ended March 31, 2013 and 2012, cash distributions paid to our general partner included incentive distributions of $60.4 million and $36.5 million, respectively.

In April 2013, our general partner declared a cash distribution of $0.715 per unit ($2.86 per unit on an annualized basis) for the first quarter of 2013, which will be paid on May 15, 2013, to unitholders of record as of April 30, 2013.

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.

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



							Variances
	Three Months Ended						2013 vs. 2012
	March 31,						Increase (Decrease)
	2013			2012			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	181.4		$	219.2		$	(37.8	)
Investing activities	(439.8		)	(278.9		)	(160.9		)
Financing activities	(209.8		)	771.3			(981.1		)
Change in cash and cash equivalents	(468.2		)	711.6			(1,179.8		)
Cash and cash equivalents at beginning of period	537.1			35.1			502.0
Cash and cash equivalents at end of period	$	68.9		$	746.7		$	(677.8	)

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 $201.4 million for the three months ended March 31, 2013, compared with $291.3 million for the same period in 2012. The decrease was due primarily to a decrease in net margin and an increase in operating expenses as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $20.0 million for the three months ended March 31, 2013, compared with a decrease of $72.1 million for the same period in 2012. This change is due primarily to the change in accounts receivable and accounts payable resulting from the timing of receipt of cash from customers and payments to vendors and suppliers, which vary from period to period. This change is also due to the change in NGL volumes in storage and commodity imbalances.

Investing Cash Flows - Cash used in investing activities increased for the three months ended March 31, 2013, compared with the same period in 2012, 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 used in financing activities increased during the three months ended March 31, 2013, compared with cash provided by financing activities for the same period in 2012. The change is a result of the issuance of common units in 2012 and an increase in cash distribution paid to our general and limited partners.

REGULATORY

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ENVIRONMENTAL AND SAFETY MATTERS

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

Environmental Matters - We are subject to multiple historical preservation, wildlife preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or 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. For example, 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 and/or other regulatory or permitting mandates 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 statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or 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 on 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 liquids 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 previously untested pipelines operating above 30-percent yield strength in high-consequence areas.

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, analogous state laws and/or regulations promulgated thereunder, 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 monitor all relevant federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us to our distribution customers who are not otherwise required to report their own emissions and the emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise. Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that requires the annual reporting of vented and fugitive emissions of methane from certain facilities beginning with the reporting of 2011 fugitive emissions in 2012.

Our 2011 total reported emissions were approximately 50.1 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 and produced, as if all such fuel and NGL products were combusted. The additional cost to gather and report this emission data did not have, and we do not expect

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it 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. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

The EPA’s rule on air quality standards titled RICE NESHAP initially included a compliance date in 2013. Subsequent industry appeals and settlements with the EPA have extended timelines associated with the final RICE NESHAP rule. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

CERCLA - The federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) that caused and/or contributed to the release of a hazardous substance into the environment. These persons include but are not limited to the owner or operator of a facility where the release occurred and/or 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. We do not expect our responsibilities under CERCLA will have a material impact on our respective 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 - The United States Department of 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.

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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 the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities.

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 natural gas during pipeline and facility maintenance and operations.

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 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.

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;

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•	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;


•	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 Oklahoma Corporation Commission, Kansas Corporation Commission, 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;

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•	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.


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 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. At March 31, 2013, and December 31, 2012, we had forward-starting interest-rate swaps with notional amounts totaling $400 million that have been 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.


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 first quarter ended March 31, 2013, 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

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


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.

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



Exhibit No.		Exhibit Description

	10.1	Amendment No. 1 to Equity Distribution Agreement dated January 23, 2013, by and among ONEOK Partners, L.P. and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on January 23, 2013 (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 Derek S. Reiners 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 Derek S. Reiners 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 months ended March 31, 2013 and 2012; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2013 and 2012; (iv) Consolidated Balance Sheets at March 31, 2013, and December 31, 2012; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012; (vi) Consolidated Statement of Changes in Equity for the three months ended March 31, 2013; and (vii) Notes

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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: May 1, 2013		By:	/s/ Derek S. Reiners
			Derek S. Reiners
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant)