Edgar Filing: ONEOK INC /NEW/

OKE-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 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)



Oklahoma	73-1520922
(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

On April 25, 2013, the Company had 206,107,055 shares of common stock outstanding.

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ONEOK, Inc.

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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	11
	Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2013	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	59
Part II.	Other Information
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3.	Defaults Upon Senior Securities	60
Item 4.	Mine Safety Disclosures	60
Item 5.	Other Information	60
Item 6.	Exhibits	60
Signature		62

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors, divisions and 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 IA, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.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, Corporate Governance Guidelines and Director Independence Guidelines 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
Bcf/d	Billion cubic feet per day
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
GAAP	Accounting principles generally accepted in the United States of America
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDCs	Local distribution companies
LIBOR	London Interbank Offered Rate
MBbl/d	Thousand barrels per day
Mcf	Thousand cubic feet
MDth/d	Thousand dekatherms per day
Midwestern Gas Transmission	Midwestern Gas Transmission Company
MMBtu	Million British thermal units
MMBtu/d	Million British thermal units per day
MMcf	Million cubic feet
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
OCC	Oklahoma Corporation Commission
ONEOK	ONEOK, Inc.
ONEOK Credit Agreement	ONEOK’s $1.2 billion revolving credit agreement dated April 5, 2011, as amended
ONEOK Partners	ONEOK Partners, L.P.

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ONEOK Partners Credit Agreement	ONEOK Partners’ $1.2 billion revolving credit agreement dated August 1, 2011, as amended
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
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
VAR	Value-at-Risk
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, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars, except per share amounts)
Revenues	$	3,541,445		$	3,414,600
Cost of sales and fuel	2,917,993			2,771,013
Net margin	623,452			643,587
Operating expenses
Operations and maintenance	223,603			192,881
Depreciation and amortization	90,221			83,409
Goodwill impairment	—			10,255
General taxes	35,820			31,177
Total operating expenses	349,644			317,722
Gain on sale of assets	41			57
Operating income	273,849			325,922
Equity earnings from investments (Note K)	25,855			34,620
Allowance for equity funds used during construction	9,087			975
Other income	7,364			9,861
Other expense	(2,596		)	(2,274		)
Interest expense (net of capitalized interest of $12,868 and $8,977, respectively)	(80,437		)	(75,815		)
Income before income taxes	233,122			293,289
Income taxes	(67,417		)	(73,839		)
Income from continuing operations	165,705			219,450
Income from discontinued operations, net of tax (Note B)	—			762
Gain on sale of discontinued operations, net of tax (Note B)	—			13,250
Net income	165,705			233,462
Less: Net income attributable to noncontrolling interests	53,184			110,597
Net income attributable to ONEOK	$	112,521		$	122,865
Amounts attributable to ONEOK:
Income from continuing operations	$	112,521		$	108,853
Income from discontinued operations	—			14,012
Net income	$	112,521		$	122,865
Basic earnings per share:
Income from continuing operations (Note I)	$	0.55		$	0.52
Income from discontinued operations	—			0.07
Net income	$	0.55		$	0.59
Diluted earnings per share:
Income from continuing operations (Note I)	$	0.54		$	0.51
Income from discontinued operations	—			0.07
Net Income	$	0.54		$	0.58
Average shares (thousands)
Basic	205,479			207,617
Diluted	209,458			211,852
Dividends declared per share of common stock	$	0.36		$	0.305

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars)
Net income	$	165,705		$	233,462
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management assets/liabilities, net of tax of $3,958 and $(19,094), respectively	(13,652		)	47,573
Realized (gains) losses in net income, net of tax of $(4,695) and $(1,615), respectively	7,295			(1,180		)
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $38 and $(141), respectively	(62		)	224
Change in pension and postretirement benefit plan liability, net of tax of $4,708 and $3,644, respectively	(7,462		)	(5,777		)
Total other comprehensive income (loss), net of tax	(13,881		)	40,840
Comprehensive income	151,824			274,302
Less: Comprehensive income attributable to noncontrolling interests	45,658			124,161
Comprehensive income attributable to ONEOK	$	106,166		$	150,141

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
(Unaudited)	2013		2012
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	143,947	$	583,618
Accounts receivable, net	1,261,804		1,349,371
Gas and natural gas liquids in storage	302,473		517,014
Commodity imbalances	75,629		90,211
Energy marketing and risk management assets (Notes C and D)	11,656		48,577
Other current assets	154,154		175,869
Total current assets	1,949,663		2,764,660
Property, plant and equipment
Property, plant and equipment	13,560,483		13,088,991
Accumulated depreciation and amortization	3,039,265		2,974,651
Net property, plant and equipment	10,521,218		10,114,340
Investments and other assets
Investments in unconsolidated affiliates (Note K)	1,220,129		1,221,405
Goodwill and intangible assets	994,289		996,206
Other assets	760,920		758,664
Total investments and other assets	2,975,338		2,976,275
Total assets	$	15,446,219	$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Continued)
	March 31,			December 31,
(Unaudited)	2013			2012
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	10,771		$	10,855
Notes payable (Note E)	551,250			817,170
Accounts payable	1,205,248			1,333,489
Commodity imbalances	201,553			272,436
Energy marketing and risk management liabilities (Notes C and D)	10,323			9,990
Other current liabilities	357,880			369,054
Total current liabilities	2,337,025			2,812,994
Long-term debt, excluding current maturities (Note F)	6,513,327			6,515,372
Deferred credits and other liabilities
Deferred income taxes	1,678,887			1,592,802
Other deferred credits	712,847			701,657
Total deferred credits and other liabilities	2,391,734			2,294,459
Commitments and contingencies (Note M)
Equity (Note G)
ONEOK shareholders’ equity:
Common stock, $0.01 par value:
authorized 600,000,000 shares; issued 245,811,180 shares and outstanding 206,088,765 shares at March 31, 2013; issued 245,811,180 shares and outstanding 204,935,043 shares at December 31, 2012	2,458			2,458
Paid-in capital	1,267,735			1,324,698
Accumulated other comprehensive loss (Note H)	(223,153		)	(216,798		)
Retained earnings	2,097,764			2,059,024
Treasury stock, at cost: 39,722,415 shares at March 31, 2013, and 40,876,137 shares at December 31, 2012	(1,010,450		)	(1,039,773		)
Total ONEOK shareholders’ equity	2,134,354			2,129,609
Noncontrolling interests in consolidated subsidiaries	2,069,779			2,102,841
Total equity	4,204,133			4,232,450
Total liabilities and equity	$	15,446,219		$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
(Unaudited)	2013			2012
	(Thousands of dollars)
Operating activities
Net income	$	165,705		$	233,462
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	90,221			83,417
Impairment of goodwill	—			10,255
Gain on sale of discontinued operations	—			(13,250		)
Equity earnings from investments	(25,855		)	(34,620		)
Distributions received from unconsolidated affiliates	23,495			36,879
Deferred income taxes	68,107			51,411
Share-based compensation expense	16,756			5,008
Allowance for equity funds used during construction	(9,087		)	(975		)
Gain on sale of assets	(41		)	(57		)
Other	(2,227		)	28,501
Changes in assets and liabilities:
Accounts receivable	90,953			180,413
Gas and natural gas liquids in storage	214,541			251,227
Accounts payable	(103,690		)	(176,674		)
Commodity imbalances, net	(56,301		)	(101,604		)
Energy marketing and risk management assets and liabilities	21,346			(122,900		)
Other assets and liabilities, net	(22,425		)	(4,408		)
Cash provided by operating activities	471,498			426,085
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(501,065		)	(348,437		)
Proceeds from sale of discontinued operations, net of cash sold	—			32,008
Contributions to unconsolidated affiliates	(3,036		)	(2,577		)
Distributions received from unconsolidated affiliates	6,698			4,062
Proceeds from sale of assets	2,596			521
Other	—			24
Cash used in investing activities	(494,807		)	(314,399		)
Financing activities
Repayment of notes payable, net	(265,920		)	(422,225		)
Issuance of debt, net of discounts	—			699,657
Long-term debt financing costs	—			(5,392		)
Repayment of debt	(1,975		)	(3,082		)
Issuance of common stock	2,831			2,228
Issuance of common units, net of issuance costs	12,819			459,735
Dividends paid	(73,781		)	(63,375		)
Distributions to noncontrolling interests	(90,336		)	(72,852		)
Cash provided by (used in) financing activities	(416,362		)	594,694
Change in cash and cash equivalents	(439,671		)	706,380
Change in cash and cash equivalents included in discontinued operations	—			8,859
Change in cash and cash equivalents from continuing operations	(439,671		)	715,239
Cash and cash equivalents at beginning of period	583,618			65,953
Cash and cash equivalents at end of period	$	143,947		$	781,192

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
	ONEOK Shareholders’ Equity
(Unaudited)	Common Stock Issued	Common Stock		Paid-in Capital			Accumulated Other Comprehensive Income (Loss)
	(Shares)	(Thousands of dollars)
January 1, 2013	245,811,180	$	2,458	$	1,324,698		$	(216,798	)
Net income	—	—		—			—
Other comprehensive income (loss)	—	—		—			(6,355		)
Common stock issued	—	—		(26,492		)	—
Common stock dividends - $0.36 per share	—	—		—			—
Issuance of common units of ONEOK Partners	—	—		2,956			—
Distributions to noncontrolling interests	—	—		—			—
Other	—	—		(33,427		)	—
March 31, 2013	245,811,180	$	2,458	$	1,267,735		$	(223,153	)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Continued)
	ONEOK Shareholders’ Equity
(Unaudited)	Retained Earnings			Treasury Stock			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
January 1, 2013	$	2,059,024		$	(1,039,773	)	$	2,102,841		$	4,232,450
Net income	112,521			—			53,184			165,705
Other comprehensive income (loss)	—			—			(7,526		)	(13,881		)
Common stock issued	—			29,323			—			2,831
Common stock dividends - $0.36 per share	(73,781		)	—			—			(73,781		)
Issuance of common units of ONEOK Partners	—			—			11,616			14,572
Distributions to noncontrolling interests	—			—			(90,336		)	(90,336		)
Other	—			—			—			(33,427		)
March 31, 2013	$	2,097,764		$	(1,010,450	)	$	2,069,779		$	4,204,133

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ONEOK, INC. 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. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2013, are not necessarily indicative of the results that may be expected for a 12-month period.

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

Stock Split - In June 2012, we completed a two-for-one split of our common stock. We have adjusted all share and per-share amounts contained herein to be presented on a post-split basis.

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, of 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 H 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 C for additional disclosures.

In July 2012, the FASB issued ASU 2012-02, “Testing Indefinite-lived Intangible Assets for Impairment,” which allows companies to perform a “qualitative” assessment to determine whether further impairment testing of indefinite-lived intangible assets is necessary. Under the revised standard, an entity is not required to calculate the fair value of an indefinite-lived intangible asset and perform the quantitative impairment test unless the entity determines that it is more likely than not that the asset is impaired. An entity has the option to bypass the qualitative assessment and perform the quantitative impairment test for any indefinite-lived intangible assets in any period. We expect the impact of this guidance to be immaterial when we adopt it for our annual assessments in July 2013.


B.	DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized a gain on the sale of approximately $13.5 million, net of taxes of $8.3 million. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report. For the month ended January 31, 2012, ONEOK Energy Marketing Company had revenues of $27.6 million and pre-tax income of $1.2 million.

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C.	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 market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value 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. Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money-market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. 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. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets. 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.

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



	March 31, 2013
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	36,414		$	5,147		$	8,351		$	49,912		$	(40,680	)	$	9,232
Physical contracts	—			907			2,452			3,359			(92		)	3,267
Interest-rate contracts	—			17,711			—			17,711			—			17,711
Total derivatives	36,414			23,765			10,803			70,982			(40,772		)	30,210
Trading securities (b)	7,859			—			—			7,859			—			7,859
Available-for-sale investment securities (c)	1,842			—			—			1,842			—			1,842
Total assets	$	46,115		$	23,765		$	10,803		$	80,683		$	(40,772	)	$	39,911

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(40,357	)	$	(578	)	$	(8,681	)	$	(49,616	)	$	45,734		$	(3,882	)
Physical contracts	—			(2,505		)	(4,467		)	(6,972		)	92			(6,880		)
Total derivatives	(40,357		)	(3,083		)	(13,148		)	(56,588		)	45,826			(10,762		)
Fair value of firm commitments (d)	—			—			(535		)	(535		)	—			(535		)
Total liabilities	$	(40,357	)	$	(3,083	)	$	(13,683	)	$	(57,123	)	$	45,826		$	(11,297	)

(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At March 31, 2013, we held $1.3 million of cash collateral and had posted $27.7 million of cash collateral with various counterparties.

(b) - Included in our Consolidated Balance Sheets as other current assets.

(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2012
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	69,957		$	10,780		$	7,107		$	87,844		$	(51,602	)	$	36,242
Physical contracts	—			2,083			2,032			4,115			(151		)	3,964
Interest-rate contracts	—			10,923			—			10,923			—			10,923
Total derivatives	69,957			23,786			9,139			102,882			(51,753		)	51,129
Trading securities (b)	5,978			—			—			5,978			—			5,978
Available-for-sale investment securities (c)	2,027			—			—			2,027			—			2,027
Total assets	$	77,962		$	23,786		$	9,139		$	110,887		$	(51,753	)	$	59,134

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(35,172	)	$	(1,737	)	$	(7,177	)	$	(44,086	)	$	33,878		$	(10,208	)
Physical contracts	—			—			(279		)	(279		)	151			(128		)
Total derivatives	(35,172		)	(1,737		)	(7,456		)	(44,365		)	34,029			(10,336		)
Fair value of firm commitments (d)	—			—			(1,280		)	(1,280		)	—			(1,280		)
Total liabilities	$	(35,172	)	$	(1,737	)	$	(8,736	)	$	(45,645	)	$	34,029		$	(11,616	)

(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2012, we held $17.7 million of cash collateral and had posted $4.5 million of cash collateral with various counterparties.

(b) - Included in our Consolidated Balance Sheets as other current assets.

(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

Our Level 1 fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices and actively quoted prices for equity securities. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil. Also included in Level 1 are equity securities.

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. Also included in Level 3 are the fair values of firm commitments. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. The significant unobservable inputs used are the unpublished forward basis and index curves. Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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The following tables set forth the reconciliation of our Level 3 fair value measurements for the periods indicated:



	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2013	$	1,683		$	(1,280	)	$	403
Total realized/unrealized gains (losses):
Included in earnings (a)	(4,033		)	745			(3,288		)
Included in other comprehensive income (loss)	(1,902		)	—			(1,902		)
Transfers into Level 3	294			—			294
Transfers out of Level 3	1,613			—			1,613
March 31, 2013	$	(2,345	)	$	(535	)	$	(2,880	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held at March 31, 2013 (a)	$	(185	)	$	177		$	(8	)

(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.



	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)	(4,801		)	3,513			(1,288		)
Included in other comprehensive income (loss)	5,785			—			5,785
Sale of discontinued operations	(3,636		)	—			(3,636		)
Transfers out of Level 3	(4,504		)	—			(4,504		)
March 31, 2012	$	17,948		$	(3,770	)	$	14,178
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held at March 31, 2012 (a)	$	(4,687	)	$	1,498		$	(3,189	)

(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments. We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. We had no transfers into or out of Level 1 during the periods presented. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

Our Level 3 fair value measurements based on unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment, are not material at March 31, 2013.

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. Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market. The estimated fair value of our consolidated long-term debt, including current maturities, was $7.3 billion at March 31, 2013, and $7.5 billion at December 31, 2012. The book value of long-term debt, including current maturities, was $6.5 billion at March 31, 2013, and December 31, 2012. The estimated fair value of the aggregate of ONEOK’s and ONEOK Partners’ senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.

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D.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. These risks include the following:

•

Commodity-price risk - We are exposed 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 commodity derivative instruments such as futures, physical-forward contracts, swaps and options to mitigate the commodity-price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage. Commodity-price volatility may have a significant impact on the fair value of our derivative instruments as of a given date;

•

Basis risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price differentials between pipeline receipt and delivery locations. Our firm transportation capacity allows us to purchase natural gas at a pipeline receipt point and sell natural gas at a pipeline delivery point. As market conditions permit, our Energy Services segment periodically enters into basis swaps between the transportation receipt and delivery points in order to protect the fair value of these location price differentials related to our firm commitments;

•

Currency exchange-rate risk - As a result of our Energy Services segment’s activities in Canada, we are exposed to the risk of loss in cash flows and future earnings from adverse changes in currency exchange rates on our commodity purchases and sales, primarily related to our firm transportation and storage contracts that are transacted in a currency other than our functional currency, the United States dollar. To reduce our exposure to exchange-rate fluctuations, we may use physical-forward transactions, which result in a two-way flow of currency on the settlement date in which we exchange United States dollars for Canadian dollars with another party; and


•	Interest-rate risk - We are also subject to fluctuations in interest rates. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps.

The following derivative instruments are used to manage our exposure to these risks:


•	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 future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties;


•	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; and


•	Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity, at a fixed price, within a specified period of time. Options may either be standardized and exchange traded or customized and nonexchange traded.

Our objectives for entering into such contracts include but are not limited to:


•	reducing the variability of cash flows by locking in the price for all or a portion of anticipated index-based physical purchases and sales, transportation fuel requirements, asset management transactions and customer-related business activities;


•	locking in a price differential to protect the fair value between transportation receipt and delivery points and to protect the fair value of natural gas or NGLs that are purchased in one month and sold in a later month;


•	reducing our exposure to fluctuations in interest and foreign currency exchange rates; and


•	reducing variability in cash flows from changes in interest rates associated with forecasted debt issuances.

Our Energy Services segment also enters into derivative contracts for financial trading purposes primarily to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity inefficiencies, which allow us to capture additional margin. Financial trading activities are executed generally using financially settled derivatives and are normally short term in nature.

With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity prices can impact our financial position and results of operations. The net open positions are managed actively, and the impact of the changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.

Our Natural Gas Distribution segment also uses derivative instruments to hedge the cost of a portion of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural gas.

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The use of these derivative instruments and the associated recovery of these costs have been approved by the OCC, KCC and regulatory authorities in certain of our Texas jurisdictions.

ONEOK Partners has forward-starting interest-rate swaps designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At March 31, 2013, and December 31, 2012, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $400 million.

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.

If certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currency. Certain nontrading derivative transactions, which are economic hedges of our accrual transactions such as our storage and transportation contracts, do not qualify for hedge accounting treatment.

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

Gains or losses associated with the fair value of derivative instruments entered into by our Natural Gas Distribution segment are included in, and recoverable through, the monthly purchased-gas cost mechanism.

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 asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value 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 presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts. All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income. The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis. Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.

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

Fair Values of Derivative Instruments - The following table sets forth the fair values of our derivative instruments for our continuing and discontinued operations for the periods indicated:



	March 31, 2013					December 31, 2012
	Fair Values of Derivatives (a)					Fair Values of Derivatives (a)
	Assets		(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	15,292	$	(16,980	)	$	47,516	(b)	$	(4,885	)
Physical contracts	51		(3,341		)	56			(126		)
Interest-rate contracts	17,711		—			10,923			—
Total derivatives designated as hedging instruments	33,054		(20,321		)	58,495			(5,011		)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts	12,503		(9,018		)	24,970			(25,009		)
Physical contracts	3,308		(3,631		)	4,059			(153		)
Trading instruments
Financial contracts	22,117		(23,618		)	15,358			(14,192		)
Total derivatives not designated as hedging instruments	37,928		(36,267		)	44,387			(39,354		)
Total derivatives	$	70,982	$	(56,588	)	$	102,882		$	(44,365	)

(a) - Included on a net basis in energy marketing and risk management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.

(b) - Includes $16.9 million of derivative net assets and ineffectiveness associated with cash flow hedges of inventory related to certain financial contracts that were used to hedge forecasted purchases and sales of natural gas. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).

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Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for our continuing and discontinued operations for the periods indicated:



		March 31, 2013					December 31, 2012
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Futures, forwards and swaps	0.7		(67.0		)	—		(85.1		)
- Crude oil and NGLs (MMbbl)	Futures, forwards and swaps	—		(3.5		)	—		(1.1		)
Basis
- Natural gas (Bcf)	Futures, forwards and swaps	0.7		(56.3		)	—		(56.3		)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	$	—		$	400.0	$	—

Fair value hedges
Basis
- Natural gas (Bcf)	Futures, forwards and swaps	65.6		(65.6		)	59.1		(59.1		)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Futures, forwards and swaps	108.6		(107.3		)	60.7		(60.4		)
	Options	92.5		(75.5		)	102.1		(100.8		)
Basis
- Natural gas (Bcf)	Futures, forwards and swaps	82.2		(84.0		)	80.2		(81.7		)
Index
- Natural gas (Bcf)	Futures, forwards and swaps	23.6		(19.0		)	20.3		(22.3		)

These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and consequently do not reflect our actual exposure to market or credit risk.

Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at March 31, 2013, includes losses of approximately $1.1 million, net of tax, related to these hedges that will be recognized within the next 33 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $0.9 million in net losses over the next 12 months, and we will recognize net losses of $0.2 million thereafter. The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $55.8 million, net of tax, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $5.4 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 ONEOK Partners’ 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 ONEOK Partners debt.

For the three months ended March 31, 2012, net margin in our Consolidated Statement of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas. As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceeded the amount expected to be recovered through sales of that inventory after considering related sales hedges, which required reclassification of the loss from accumulated other comprehensive loss to current period earnings.

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



Derivatives in Cash Flow Hedging Relationships	Three Months Ended
	March 31,
	2013			2012
	(Thousands of dollars)
Commodity contracts	$	(24,398	)	$	45,565
Interest-rate contracts	6,788			21,102
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(17,610	)	$	66,667

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



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	Three Months Ended
		March 31,
		2013			2012
		(Thousands of dollars)
Commodity contracts	Revenues	$	5,434		$	62,369
Commodity contracts	Cost of sales and fuel	(13,987		)	(61,977		)
Interest-rate contracts	Interest expense	(3,437		)	(827		)
Total loss reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(11,990	)	$	(435	)

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 will discontinue cash flow hedge treatment, which will affect earnings. For the three months ended March 31, 2013 and 2012, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable.

Other Derivative Instruments - The following table sets forth the effect of our derivative instruments that are not part of a hedging relationship in our Consolidated Statements of Income for our continuing and discontinued operations for the periods indicated:



Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Three Months Ended
		March 31,
		2013			2012
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	(1,662	)	$	315
Commodity contracts - nontrading (a)	Cost of sales and fuel	633			2,963
Total gain (loss) recognized in income on derivatives		$	(1,029	)	$	3,278

(a) - Amounts are presented net of deferred gains (losses) associated with derivatives entered into by our Natural Gas Distribution segment.

Our Natural Gas Distribution segment held no natural gas call options at March 31, 2013, and held call options with premiums totaling $9.6 million at December 31, 2012. The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism. We realized a loss of $6.6 million for the three months ended March 31, 2013, and an immaterial loss for the three months ended March 31, 2012, associated with the decline in the value and expiration of option contracts, which are deferred as part of our unrecovered purchase-gas costs.

Fair Value Hedges - Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments. Cost of sales and fuel in our Consolidated Statements of Income includes losses of $0.1 million and gains of $0.5 million for the three months ended March 31, 2013 and 2012, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include gains of $0.3 million and losses of $1.8 million for the three months ended March 31, 2013 and 2012, respectively, to recognize the change in fair value of the related hedged firm commitments. The ineffectiveness related to these hedges was not material for the three months ended March 31, 2013 and 2012.

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Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers we use internally developed credit ratings.

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position at March 31, 2013, was not material.

The counterparties to our derivative contracts consist primarily of major energy companies, LDCs, electric utilities, financial institutions and commercial and industrial end-users. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

At March 31, 2013, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial and utility sectors.


E.	CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - The ONEOK Credit Agreement, which is scheduled to expire in March 2018, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become due and payable immediately. At March 31, 2013, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 49.3 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

Under the terms of the ONEOK Credit Agreement, ONEOK may 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. The ONEOK Credit Agreement is available for general corporate purposes, including repayment of ONEOK’s commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Credit Agreement. The ONEOK 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 137.5 basis points, and the annual facility fee is 20 basis points based on our current credit rating.

At March 31, 2013, ONEOK had $551.3 million of commercial paper outstanding and $1.9 million in letters of credit issued, leaving approximately $646.8 million of credit available under the ONEOK Credit Agreement.

In March 2013, we amended the ONEOK Credit Agreement to extend its maturity to March 28, 2018, from April 5, 2016, and reduce the facility fee and interest-rate margins for any borrowings after the amendment’s effective date.

ONEOK Partners Credit Agreement - The ONEOK Partners 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 the ONEOK Partners 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 ONEOK Partners consummates 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 ONEOK Partners in the ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK

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Partners Credit Agreement, if any, may become due and payable immediately. At March 31, 2013, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

The ONEOK Partners Credit Agreement includes a $100 million sublimit for the issuance of standby letters of credit and also features an option that allows ONEOK Partners 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. The ONEOK Partners Credit Agreement is available for general partnership purposes. Amounts outstanding under our commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. At March 31, 2013, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners Credit Agreement.

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

Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.


F.	LONG-TERM DEBT

In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022. The net proceeds from the offering, after deducting underwriting discounts and offering expenses, were approximately $694.3 million.

ONEOK Partners repaid its $350 million, 5.9-percent senior notes at maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.


G.	EQUITY

The following table sets forth the changes in equity attributable to us and our noncontrolling interests, including other comprehensive income, net of tax, for the periods indicated:



	Three Months Ended									Three Months Ended
	March 31, 2013									March 31, 2012
	ONEOK Shareholders’ Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity			ONEOK Shareholders’ Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,129,609		$	2,102,841		$	4,232,450		$	2,238,573		$	1,561,159		$	3,799,732
Net income	112,521			53,184			165,705			122,865			110,597			233,462
Other comprehensive income (loss)	(6,355		)	(7,526		)	(13,881		)	27,276			13,564			40,840
Common stock issued	2,831			—			2,831			2,561			—			2,561
Common stock dividends	(73,781		)	—			(73,781		)	(63,375		)	—			(63,375		)
Issuance of common units of ONEOK Partners	2,956			11,616			14,572			(51,100		)	510,835			459,735
Distributions to noncontrolling interests	—			(90,336		)	(90,336		)	—			(72,852		)	(72,852		)
Other	(33,427		)	—			(33,427		)	(20,648		)	—			(20,648		)
Ending balance	$	2,134,354		$	2,069,779		$	4,204,133		$	2,256,152		$	2,123,303		$	4,379,455

Dividends - Dividends paid on our common stock to shareholders of record at the close of business on January 31, 2013, were $0.36 per share. A dividend of $0.36 per share was declared for shareholders of record on April 30, 2013, payable May 15, 2013.

See Note L for a discussion of ONEOK Partners’ issuance of common units and distributions to noncontrolling interests.

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H.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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



	Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities (a)			Unrealized Holding Gains (Losses) on Investment Securities (a)			Pension and Postretirement Benefit Plan Obligations (a)			Accumulated Other Comprehensive Income (Loss) (a)
	(Thousands of dollars)
January 1, 2013	$	(55,030	)	$	1,034		$	(162,802	)	$	(216,798	)
Other comprehensive income (loss) before reclassifications	(6,274		)	(62		)	(18,720		)	(25,056		)
Amounts reclassified from accumulated other comprehensive income (loss)	7,443			—			11,258			18,701
Net current-period other comprehensive income (loss) attributable to ONEOK	1,169			(62		)	(7,462		)	(6,355		)
March 31, 2013	$	(53,861	)	$	972		$	(170,264	)	$	(223,153	)

(a) All amounts are presented net of tax.

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) on our Consolidated Statements of Income for the three months ended March 31, 2013:



Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)			Affected Line Item in the Consolidated Statement of Income
	(Thousand of dollars)
Unrealized gains (losses) on energy marketing and risk management assets/liabilities
Commodity contracts	$	(5,434	)	Revenues
Commodity contracts	13,987			Cost of sales and fuel
Interest rate contracts	3,437			Interest expense
	11,990			Income before income taxes
	(4,695		)	Income tax expense
	7,295			Net income
Noncontrolling interest	(148		)	Less: Net income attributable to noncontrolling interest
	$	7,443		Net income attributable to ONEOK

Pension and postretirement benefit plan obligations (a)
Amortization of net loss	19,727
Amortization of unrecognized prior service cost	(1,438		)
Amortization of unrecognized net asset at adoption	$	71
	18,360			Income before income taxes
	(7,102		)	Income tax expense
	$	11,258		Net income attributable to ONEOK

Total reclassifications for the period attributable to ONEOK	$	18,701		Net income attributable to ONEOK

(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note J for additional detail of our net periodic benefit cost.

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I.	EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:



	Three Months Ended March 31, 2013
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	112,521	205,479	$	0.55
Diluted EPS from continuing operations
Effect of dilutive securities	—		3,979
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	112,521	209,458	$	0.54



	Three Months Ended March 31, 2012
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	108,853	207,617	$	0.52
Diluted EPS from continuing operations
Effect of dilutive securities	—		4,235
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	108,853	211,852	$	0.51

There were no option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2013 and 2012.


J.	EMPLOYEE BENEFIT PLANS

The following table sets forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:



	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,736		$	5,325		$	1,145		$	1,240
Interest cost	13,612			14,809			2,911			3,473
Expected return on assets	(20,318		)	(20,689		)	(3,065		)	(2,671		)
Amortization of unrecognized net asset at adoption	—			—			71			718
Amortization of unrecognized prior service cost	230			242			(1,668		)	(2,063		)
Amortization of net loss	16,570			12,111			3,157			3,296
Net periodic benefit cost	$	15,830		$	11,798		$	2,551		$	3,993

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K.	UNCONSOLIDATED AFFILIATES

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment:



	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 ONEOK Partners	$	30,193	$	40,941

We incurred expenses in transactions with unconsolidated affiliates of $7.8 million, and $9.8 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 ONEOK Partners’ equity earnings from Northern Border Pipeline in the first quarter 2013 and are expected to reduce equity earnings and cash distributions from Northern Border Pipeline in the future.


L.	ONEOK PARTNERS

Equity Issuance - ONEOK Partners has an “at-the-market” equity program for the offer and sale from time to time of its common units up to an aggregate amount of $300 million. The program allows ONEOK Partners to offer and sell its common units at prices ONEOK Partners deems 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 ONEOK Partners and the sales agent. ONEOK Partners is under no obligation to offer and sell common units under the program.

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

In March 2012, ONEOK Partners 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. ONEOK Partners also sold 8.0 million common units to us in a private placement, generating net proceeds of approximately $460 million. In conjunction with

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the issuances, we contributed approximately $19 million in order to maintain our 2-percent general partner interest in ONEOK Partners.

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction. If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital. As a result of ONEOK Partners’ issuance of common units, we recognized an increase to paid-in capital of approximately $3.0 million, net of taxes of $1.6 million, in 2013.

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below at March 31, 2013:



General partner interest	2.0	%
Limited partner interest (a)	41.3	%
Total ownership interest	43.3	%

(a) - Represents 19.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units.

Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in ONEOK Partners’ partnership agreement, as amended. Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner. The 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 ONEOK Partners’ partnership agreement, as amended, the 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.

The following table shows ONEOK Partners’ 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 noncontrolling interest	90,189		72,609
Total distributions paid	$	220,924	$	164,083

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The following table shows ONEOK Partners’ 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 noncontrolling interest	91,039		80,662
Total distributions declared	$	223,428	$	187,952

Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for the distributions we receive. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement. See Note N for more information on ONEOK Partners’ results.

Affiliate Transactions - We have certain transactions with ONEOK Partners and its subsidiaries, which collectively comprise our ONEOK Partners segment.

ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment. In addition, a portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Natural Gas Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations.

We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are incurred specifically on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis.

The following table shows ONEOK Partners’ transactions with us 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


M.	COMMITMENTS AND CONTINGENCIES

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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, emissions 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.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater.

Of the 12 sites, we have begun soil remediation on 11 sites. Regulatory closure has been achieved at three locations, and we have completed or are near completion of soil remediation at eight sites. We have begun site assessment at the remaining site where no active remediation has occurred.

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 or 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 emissions 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, 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 known 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 emissions 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

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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.

Legal Proceedings - Gas Index Pricing Litigation - As previously reported, ONEOK and its subsidiary, ONEOK Energy Services Company L.P. (OESC), along with several other energy companies, are defending multiple lawsuits arising from alleged market manipulation or false reporting of natural gas prices to natural gas-index publications. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit reversed the summary judgments that had been granted in favor of ONEOK, OESC and other unaffiliated defendants in the following cases: Reorganized FLI, Learjet, Arandell, Heartland and NewPage. The Ninth Circuit also reversed the summary judgment that had been granted in favor of OESC on all state law claims asserted in the Sinclair case. The Ninth Circuit remanded the cases back to the United States District Court for the District of Nevada for further proceedings.

Because of the uncertainty surrounding the Gas Index Pricing Litigation, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these matters could result in future charges that may be material to our results of operations.

Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of our operations. While the results of these various other litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses on 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.


N.	SEGMENTS

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


•	our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners. At March 31, 2013, we have a 43.3-percent ownership interest and control ONEOK Partners through our ownership of its general partner

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interest. ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs and NGL products. We and ONEOK Partners maintain significant financial and corporate governance separations. We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually;


•	our Natural Gas Distribution segment is comprised of our regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and


•	our Energy Services segment markets natural gas to wholesale customers.

Other and eliminations consist of the operating and leasing operations of our headquarters building and related parking facility and other amounts needed to reconcile our reportable segments to our consolidated financial statements.

Accounting Policies - We evaluate performance based principally on each segment’s operating income and equity earnings. The accounting policies of the segments are the same as those described in Note A of the Notes to Consolidated Financial Statements in our Annual Report. Intersegment sales are recorded on the same basis as sales to unaffiliated customers and are discussed in further detail in Note L. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel, and storage and transportation costs.

Customers - For the three months ended March 31, 2013 and 2012, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

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	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,434,813	$	635,931	$	470,195		$	506		$	3,541,445
Intersegment revenues	82,634		2		77,385			(160,021		)	—
Total revenues	$	2,517,447	$	635,933	$	547,580		$	(159,515	)	$	3,541,445

Net margin	$	370,599	$	251,674	$	674		$	505		$	623,452
Operating costs	138,264		116,171		5,008			(20		)	259,423
Depreciation and amortization	54,678		34,867		71			605			90,221
Gain on sale of assets	41		—		—			—			41
Operating income (loss)	$	177,698	$	100,636	$	(4,405	)	$	(80	)	$	273,849

Equity earnings from investments	$	25,855	$	—	$	—		$	—		$	25,855
Investments in unconsolidated affiliates	$	1,220,129	$	—	$	—		$	—		$	1,220,129
Total assets	$	10,696,007	$	3,493,533	$	364,049		$	892,630		$	15,446,219
Noncontrolling interests in consolidated subsidiaries	$	4,706	$	—	$	—		$	2,065,073		$	2,069,779
Capital expenditures	$	443,464	$	53,729	$	—		$	3,872		$	501,065

(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $176.6 million, net margin of $119.2 million and operating income of $55.1 million.

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Three Months Ended March 31, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,518,383	$	516,923	$	378,698		$	596		$	3,414,600
Intersegment revenues	75,705		841		82,110			(158,656		)	—
Total revenues	$	2,594,088	$	517,764	$	460,808		$	(158,060	)	$	3,414,600

Net margin	$	421,090	$	237,348	$	(15,446	)	$	595		$	643,587
Operating costs	115,870		104,986		4,839			(1,637		)	224,058
Depreciation and amortization	49,256		33,520		129			504			83,409
Goodwill impairment	—		—		10,255			—			10,255
Gain on sale of assets	57		—		—			—			57
Operating income (loss)	$	256,021	$	98,842	$	(30,669	)	$	1,728		$	325,922

Equity earnings from investments	$	34,620	$	—	$	—		$	—		$	34,620
Investments in unconsolidated affiliates	$	1,219,635	$	—	$	—		$	—		$	1,219,635
Total assets	$	9,807,189	$	3,175,009	$	401,218		$	868,660		$	14,252,076
Noncontrolling interests in consolidated subsidiaries	$	4,988	$	—	$	—		$	2,118,315		$	2,123,303
Capital expenditures	$	280,793	$	58,448	$	—		$	9,196		$	348,437

(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $171.2 million, net margin of $122.9 million and operating income of $64.6 million.

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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. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2013, are not necessarily indicative of the results that may be expected for a 12-month period.

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 ONEOK Partners’ natural gas liquids business. 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 ONEOK Partners’ natural gas processing plants and some of its customers’ natural gas processing plants connected to ONEOK Partners’ system in the Mid-Continent and Rocky Mountain regions during the first quarter 2013, which reduced natural gas liquids volumes transported and fractionated in ONEOK Partners’ natural gas liquids business and its 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 to be widespread and prolonged. See additional discussion in the “Financial Results and Operating Information” section.

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 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.

ONEOK Partners’ 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 ONEOK Partners has operations. ONEOK Partners expects 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, ONEOK Partners is 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 these regions, as well as enhancing its natural gas liquids distribution infrastructure in the Gulf Coast region. The execution of these capital investments aligns with ONEOK Partners’ focus to grow fee-based earnings. Acreage dedications and supply commitments from producers and natural gas processors in regions associated with ONEOK Partners’ growth projects are expected to provide incremental and long-term fee-based earnings and cash flows.

See discussion of ONEOK Partners’ growth projects in the “Financial Results and Operating Information” section for our ONEOK Partners segment.

Dividends/Distributions - We declared a quarterly dividend of $0.36 per share ($1.44 per share on an annualized basis) in April 2013. A cash distribution from ONEOK Partners of $0.715 per unit ($2.86 per unit on an annualized basis) was declared in April 2013 for the first quarter of 2013, an increase of 0.5 cents from the previous quarter. The quarterly dividend and distribution payments will be made May 15, 2013, to shareholders and unitholders of record at the close of business on April 30, 2013.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected 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	$	3,541.4		$	3,414.6		$	126.8		4	%
Cost of sales and fuel	2,918.0			2,771.0			147.0			5	%
Net margin	623.4			643.6			(20.2		)	(3	)%
Operating costs	259.4			224.1			35.3			16	%
Depreciation and amortization	90.2			83.4			6.8			8	%
Goodwill impairment	—			10.3			(10.3		)	(100	)%
Gain on sale of assets	—			0.1			(0.1		)	(100	)%
Operating income	$	273.8		$	325.9		$	(52.1	)	(16	)%

Equity earnings from investments	$	25.9		$	34.6		$	(8.7	)	(25	)%
Interest expense	$	(80.4	)	$	(75.8	)	$	4.6		6	%
Net income	$	165.7		$	233.5		$	(67.8	)	(29	)%
Net income attributable to noncontrolling interests	$	53.2		$	110.6		$	(57.4	)	(52	)%
Net income attributable to ONEOK	$	112.5		$	122.9		$	(10.4	)	(8	)%
Capital expenditures	$	501.1		$	348.4		$	152.7		44	%

Revenues increased for the three months ended March 31, 2013, compared with the same period last year, due to higher natural gas prices and higher natural gas and NGL sales volumes from ONEOK Partners’ completed capital projects, offset partially by lower NGL product prices, significantly narrower NGL location 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. The increase in natural gas 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 ONEOK Partners serves and lower NGL prices during the three months ended March 31, 2013, compared with the same period last year.

Operating income for the three-month period ended March 31, 2013, compared with the same period last year, reflects narrower NGL location price differentials and lower realized NGL product prices, offset partially by higher natural gas and NGL volumes from ONEOK Partners’ completed capital projects. The decrease in operating income was offset partially by our Energy Services segment due primarily to the required reclassification of deferred losses on certain financial contracts and a nonrecurring goodwill impairment charge in the first quarter 2012.

The increase in operating costs for the three months ended March 31, 2013, compared with the same period last year, was due primarily to the ONEOK Partners segment’s expanding operations as a result of several internal growth projects that were placed in service and scheduled maintenance costs.

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 ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012, offset partially by capitalized interest associated with the investments in ONEOK Partners’ growth projects.

Net income attributable to noncontrolling interests, which reflects primarily the portion of ONEOK Partners that we do not own, decreased for the three months ended March 31, 2013, compared with the same period last year, due to lower earnings in our ONEOK Partners segment.

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

ONEOK Partners

Overview - ONEOK Partners is a diversified master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States. In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.

We own approximately 92.8 million common and Class B limited partner units, and the entire 2-percent general partner interest, which, together, represented a 43.3-percent ownership interest in ONEOK Partners at March 31, 2013. We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. See Note L of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of our incentive distribution rights.

We and ONEOK Partners maintain significant financial and corporate governance separations. We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of ONEOK Partners’ businesses individually. To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business provides nondiscretionary services to producers that include gathering and processing of natural gas produced from crude-oil and natural gas wells. ONEOK Partners gathers and processes 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. It also gathers and/or processes 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 areas; and the Powder River Basin of Wyoming. In the Powder River Basin, the natural gas that ONEOK Partners gathers 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.

Natural gas pipelines business - ONEOK Partners’ natural gas pipelines business owns and operates regulated natural gas transmission pipelines and natural gas storage facilities. ONEOK Partners also provides interstate natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act.

ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Kansas and Texas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Natural gas liquids business - ONEOK Partners’ natural gas liquids business owns and operates facilities that gather, fractionate, distribute and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas where it provides nondiscretionary services to producers of NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as to third-party fractionators and pipelines. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to ONEOK Partners’ customers, such as petrochemical manufacturers, heating-fuel users, refineries and propane distributors through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the Mid-Continent and Gulf Coast NGL market centers, as well as the Midwest markets near Chicago, Illinois. ONEOK Partners’ natural gas liquids business owns and operates truck and rail-loading and unloading facilities that interconnect with its fractionation and pipeline assets. In March 2013, ONEOK Partners’ natural gas liquids business began transporting unfractionated NGLs from the Williston Basin into its completed Bakken NGL Pipeline. These unfractionated NGLs previously were transported by rail to ONEOK Partners’ Mid-Continent natural gas liquids fractionation facilities. ONEOK Partners’ natural gas liquids business will continue to use these rail terminal facilities in its NGL marketing activities.

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Growth Projects - Natural gas gathering and processing projects - ONEOK Partners’ natural gas gathering and processing business 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 ONEOK Partners to meet the rapidly growing needs of natural gas producers in those areas.

Williston Basin Processing Plants and related projects - ONEOK Partners’ 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. ONEOK Partners has acreage dedications of approximately 3.1 million acres supporting these plants. In addition, ONEOK Partners is expanding and upgrading its 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. ONEOK Partners expects 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 in service in September 2012, and the Stateline II natural gas processing facility was placed in service in 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.

ONEOK Partners plans to invest $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The new system will gather and deliver natural gas from producers in the Williston Basin to both of ONEOK Partners’ Stateline natural gas processing facilities in western Williams County, North Dakota. ONEOK Partners has secured long-term acreage dedications from producers for this new system, which are structured with POP and fee-based contractual components. ONEOK Partners has completed construction on approximately 50 percent of the infrastructure and expects it to be completed in the third quarter 2013.

ONEOK Partners expects that its capital projects will continue to provide additional revenues from POP and fee-based contracts as they are completed. ONEOK Partners expects its commodity price exposure to increase, particularly to NGL and natural gas prices, as equity volumes increase under its natural gas gathering and processing business’ POP contracts with its customers in the Williston Basin. ONEOK Partners uses derivative instruments to mitigate its sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for its share of volumes.

Cana Woodford Shale projects - ONEOK Partners plans 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 its existing natural gas transportation and natural gas liquids gathering pipelines. The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where ONEOK Partners has substantial acreage dedications from active producers. The new Canadian Valley plant is expected to cost approximately $190 million, excluding AFUDC, and is expected to be completed in the first quarter 2014. The related additional infrastructure is expected to cost approximately $160 million, excluding AFUDC, and is expected to increase ONEOK Partners’ 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. ONEOK Partners expects the routine growth capital needed to connect to new wells and expand its infrastructure to increase compared with its historical levels of routine growth capital.

Natural gas liquids projects - The growth strategy in ONEOK Partners’ natural gas liquids business 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 ONEOK Partners to make additional capital investments to expand its infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly over the next three to five years, and international demand for propane is impacting positively the NGL markets now and is expected to in the future.

ONEOK Partners’ natural gas liquids business 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 supplies from shale and other resource development areas across ONEOK Partners’ asset base and alleviate infrastructure constraints between the

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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 ONEOK Partners’ 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. ONEOK Partners expects narrow NGL price differentials to continue as new fractionators and pipelines, including ONEOK Partners’ growth projects discussed below, continue to alleviate constraints between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers.

Sterling III Pipeline - ONEOK Partners is 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 ONEOK Partners’ natural gas liquids infrastructure at Medford, Oklahoma, to its storage and fractionation facilities in Mont Belvieu, Texas. ONEOK Partners has 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 its 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 - ONEOK Partners is constructing a 75-MBbl/d fractionator, MB-2, near its 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 fractionator is estimated to be $300 million to $390 million, excluding AFUDC. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity.

MB-3 Fractionator - ONEOK Partners plans to construct a 75 MBbl/d fractionator, MB-3, near its storage facility in Mont Belvieu, Texas. In addition, ONEOK Partners plans to expand and upgrade its 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, ONEOK Partners placed in service a 12-inch diameter ethane header pipeline that creates a new point of interconnection between its Mont Belvieu, Texas, NGL fractionation and storage assets and several petrochemical customers. The new pipeline has the capacity to transport 400 MBbl/d from its 80 percent-owned, 160 MBbl/d MB-1 fractionator and its 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 - ONEOK Partners plans to construct a new 40 MBbl/d ethane/propane splitter at its 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 into service in April 2013. The unfractionated NGLs then are delivered to ONEOK Partners’ 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 ONEOK Partners’ natural gas processing plants.

ONEOK Partners 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.

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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 ONEOK Partners owns 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. ONEOK Partners’ 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, ONEOK Partners placed in service an expansion and upgrade to its 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 - ONEOK Partners plans to invest approximately $140 million, excluding AFUDC, to construct a new 95-mile natural gas liquids pipeline that will connect its 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 - ONEOK Partners constructed approximately 230 miles of natural gas liquids pipelines that expanded its existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. These pipelines expanded ONEOK Partners’ 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, ONEOK Partners installed additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d. These projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to ONEOK Partners’ 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 ONEOK Partners’ 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 for our ONEOK Partners segment 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 (loss) 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 ONEOK Partners’ natural gas liquids business, offset partially by higher natural gas and NGL volumes from ONEOK Partners’ 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 it serves and lower NGL prices during the three months ended March 31, 2013, compared with the same period last year.

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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 ONEOK Partners’ natural gas processing plants and some of its customers’ natural gas processing plants connected to ONEOK Partners’ natural gas liquids system in the Mid-Continent and Rocky Mountain regions during the first quarter 2013.

Net margin decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to 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 transportation capacity between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers was utilized by ONEOK Partners’ exchange services activities to produce fee-based earnings. This decrease was offset partially by a $2.6 million increase in marketing activities in ONEOK Partners’ natural gas liquids business;


•	a decrease of $13.0 million due primarily to lower net realized NGL product prices in ONEOK Partners’ natural gas gathering and processing business;


•	a decrease of $13.0 million due primarily to higher compression costs and less favorable contract terms associated with its volume growth primarily in the Williston Basin in ONEOK Partners’ natural gas gathering and processing business; and


•	a decrease of $9.0 million resulting from the impact of ethane rejection during the first quarter 2013 in ONEOK Partners’ natural gas liquids business; 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 ONEOK Partners’ NGL exchange services activities and higher revenues from customers with minimum volume obligations in ONEOK Partners’ natural gas liquids business; and


•	an increase of $28.2 million due primarily to volume growth in the Williston Basin from ONEOK Partners’ 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 in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the following:


•	an increase of $8.6 million in higher labor and employee-related costs associated with the growth of ONEOK Partners’ operations and completed capital projects in its natural gas gathering and processing and natural gas liquids businesses; and


•	an increase of $7.7 million from higher materials and supplies, and outside services expenses associated primarily with growth and scheduled maintenance in ONEOK Partners’ operations related to the completed capital projects in its natural gas gathering and processing and natural gas liquids businesses.

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 expense associated with ONEOK Partners’ completed capital projects, which includes the completion of its Stateline I natural gas processing plant, well connections and infrastructure projects supporting the volume growth in the Williston Basin.

Equity earnings decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to lower earnings from Overland Pass Pipeline Company and Northern Border Pipeline, in which ONEOK Partners owns a 50-percent interest in each. Overland Pass Pipeline Company’s earnings were lower as a result of lower volumes due to ethane rejection. Northern Border Pipeline’s earnings were lower due to reduced transportation rates resulting from a rate settlement with its customers that was approved by the FERC, effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower, compared with previous rates, which reduced ONEOK Partners’ 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.

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

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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 ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses. During the first quarter 2013, ONEOK Partners’ natural gas gathering and processing business connected approximately 270 new wells to its 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 ONEOK Partners segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information	2013			2012
Natural gas gathering and processing business (a)
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
Natural gas pipelines business (a)
Natural gas transportation capacity contracted (MDth/d)	5,670			5,552
Transportation capacity subscribed (d)	93		%	92		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	3.42		$	2.37
Natural gas liquids business
NGL sales (MBbl/d)	578			511
NGLs fractionated (MBbl/d) (e)	512			585
NGLs transported-gathering lines (MBbl/d) (a)	498			498
NGLs transported-distribution lines (MBbl/d) (a)	394			485
Conway-to-Mont Belvieu OPIS average price differential - ethane in ethane/propane mix ($/gallon)	$	0.01		$	0.24

(a) - Includes volumes for consolidated entities only.

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

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

(e) - Includes volumes fractionated from company-owned and third-party facilities.

Volumes in the natural gas gathering and processing business 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 ONEOK Partners’ new Stateline I 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 ONEOK Partners owns 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, ONEOK Partners tested its investment for impairment. The carrying amount of its investment at March 31, 2013, was $90.0 million, which includes $53.4 million in equity-method goodwill. ONEOK Partners estimated the fair value of its investment in Bighorn Gas Gathering using an income approach, which discounted the estimated future cash flows of its investment’s underlying assets with a discount rate reflective of its 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.

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A decline of 10 percent or more in the fair value of ONEOK Partners’ investment in Bighorn Gas Gathering would result in a noncash impairment charge. For its 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, ONEOK Partners did not identify current events or circumstances that warranted an impairment analysis or adjustment to ONEOK Partners’ carrying values. ONEOK Partners is 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.

ONEOK Partners’ 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 ONEOK Partners’ assumptions and estimates or ONEOK Partners’ assumptions and estimates change due to new information, ONEOK Partners may be exposed to future impairment charges.

The quantity and composition of NGLs received by ONEOK Partners’ natural gas gathering and processing business as payments under its various processing agreements continue to change as its new natural gas processing plants in the Williston Basin are placed in service. ONEOK Partners’ Garden Creek and Stateline I plants have the capability to recover ethane when economic conditions warrant but did not do so during the first quarter. As a result, ONEOK Partners’ first-quarter 2013 equity NGL volumes are weighted more toward propane, iso-butane, normal butane and natural gasoline, compared with last year.

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. ONEOK Partners does not expect the ultimate outcome to impact materially its results of operations.

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 ONEOK Partners’ Cana-Woodford Shale and Granite Wash projects, which 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.

Commodity-Price Risk - The following tables set forth ONEOK Partners’ natural gas gathering and processing business’ hedging information for its 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%

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ONEOK Partners expects its commodity-price sensitivity in its natural gas gathering and processing business to increase in the future as volumes increase under POP contracts with ONEOK Partners’ customers. ONEOK Partners’ commodity-price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging, and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates 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.

These estimates do not include any effects on demand for ONEOK Partners’ services or processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing margins for certain contracts.

See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on ONEOK Partners’ hedging activities.

Natural Gas Distribution

Overview - Our Natural Gas Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our LDCs serve wholesale and public authority customers. We operate subject to regulations and oversight of various regulatory agencies.

Retail Marketing Sale - On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized an after-tax gain on the sale of approximately $13.5 million.

Selected Financial Results - The following table sets forth certain selected financial results for the continuing operations of our Natural Gas Distribution segment for the periods indicated:



	Three Months Ended				Variances
	March 31,				2013 vs. 2012
Financial Results	2013		2012		Increase (Decrease)
	(Millions of dollars)
Gas sales	$	598.2	$	481.5	$	116.7		24	%
Transportation revenues	29.3		27.0		2.3			9	%
Cost of sales	384.2		280.5		103.7			37	%
Net margin, excluding other revenues	243.3		228.0		15.3			7	%
Other revenues	8.4		9.3		(0.9		)	(10	)%
Net margin	251.7		237.3		14.4			6	%
Operating costs	116.2		105.0		11.2			11	%
Depreciation and amortization	34.9		33.5		1.4			4	%
Operating income	$	100.6	$	98.8	$	1.8		2	%
Capital expenditures	$	53.7	$	58.4	$	(4.7	)	(8	)%

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The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:



Net Margin, Excluding Other Revenues	Three Months Ended				Variances
	March 31,				2013 vs. 2012
	2013		2012		Increase (Decrease)
Gas sales	(Millions of dollars)
Residential	$	176.3	$	165.1	$	11.2	7	%
Commercial	35.1		33.6		1.5		4	%
Industrial	0.7		0.6		0.1		17	%
Wholesale/public authority	1.9		1.7		0.2		12	%
Net margin on gas sales	214.0		201.0		13.0		6	%
Transportation margin	29.3		27.0		2.3		9	%
Net margin, excluding other revenues	$	243.3	$	228.0	$	15.3	7	%

Net margin increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the following:


•	an increase of $10.4 million from new rates in all three states; and


•	an increase of $1.7 million from higher transportation volumes, primarily due to higher demand from weather-sensitive customers in Kansas.

Operating costs increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to the following:


•	an increase of $5.5 million in share-based compensation costs from the appreciation in ONEOK’s share price;


•	an increase of $2.8 million in pension costs as a result of an annual change in the estimated discount rate; and


•	an increase of $2.2 million in property taxes primarily in Kansas.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading, extending service to new areas, modifications to customer-service lines, increasing system capabilities, relocating facilities to accommodate government construction and replacements. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.

Capital expenditures decreased for the three months ended March 31, 2013, compared with the same period last year, primarily as a result of the timing of pipeline replacements in Kansas and Texas and a decrease in automated meter-reading investments.

Selected Operating Information - The following tables set forth certain selected information for the regulated operations of our Natural Gas Distribution segment for the periods indicated:



	Three Months Ended
	March 31,
Number of Customers	2013	2012
Residential	1,955,909	1,944,754
Commercial	156,425	155,894
Industrial	1,166	1,250
Wholesale/public authority	2,763	2,703
Transportation	12,006	11,878
Total customers	2,128,269	2,116,479

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	Three Months Ended
	March 31,
Volumes (MMcf)	2013	2012
Gas sales
Residential	55,225	49,697
Commercial	14,807	13,097
Industrial	440	342
Wholesale/public authority	2,483	2,508
Total volumes sold	72,955	65,644
Transportation	58,709	57,532
Total volumes delivered	131,664	123,176

Residential and commercial volumes increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to colder temperatures in 2013; however, the impact on margins was mitigated largely by weather-normalization mechanisms.

Regulatory Initiatives - Oklahoma - In March 2013, Oklahoma Natural Gas (ONG) filed a Performance-Based Rate Change (PBRC) application at the OCC seeking no modification to customers’ base rates. The filing does include a small adjustment to residential, commercial and industrial customers’ monthly service charge for energy-efficiency program collections.

In May 2011, the OCC approved a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives. The agreement allows ONG to pursue key energy-efficiency programs and allows ONG to earn up to $1.5 million annually, if program objectives are achieved. In April 2013, an Administrative Law Judge recommended approval of a Joint Stipulation that had been agreed to by the parties, which, if approved by the OCC, will extend the program to include the years 2014-2016 and adjust the rebate targets.

Texas - Texas Gas Service has made annual filings for interim rate relief under the Gas Reliability Infrastructure Program (GRIP) statute with the cities of Austin, Texas, and surrounding communities in February 2013 and with El Paso, Texas, in April 2013 for approximately $4.1 million and $4.9 million, respectively. GRIP is a capital-recovery mechanism that allows for an interim rate adjustment providing recovery and a return on incremental capital investments made between rate cases.

In the normal course of business, we have filed rate cases and sought GRIP and cost-of-service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expense.

Energy Services

Overview - Our Energy Services segment is a provider of natural gas supply and risk-management services for natural gas and electric utilities and commercial and industrial customers. We use a network of leased storage and transportation capacity to supply natural gas to our customers. This network connects the major supply and demand centers throughout the United States and into Canada and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently.

We follow a strategy of optimizing our storage and cross-regional transportation capacity through the application of market knowledge and effective risk management. We seek to maximize value by actively hedging the risks associated with seasonal and location price differentials that are inherent to storage and transportation contracts. At the same time, we attempt to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market inefficiencies, which allow us to capture additional margin. Using market information, we manage these asset-based positions and seek to provide incremental margin in our trading portfolio.

To provide natural gas when our customers need it, we offer premium services and products that satisfy our customers’ nonuniform supply needs such as swing and peaking natural gas load requirements on a year-round basis. Types of premium services include next-day and no-notice services. Next-day services allow our customers to call on additional gas supply up to an amount agreed upon in a service contract and expect delivery the following day. No-notice services allow customers to call on additional natural gas supply and expect immediate delivery. We also provide weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation assets enable us to provide these services and provide us with opportunities to capture daily, monthly and seasonal value due to market inefficiencies.

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As a result of significant increases in the supply of natural gas, primarily from shale production across North America, location and seasonal natural gas price differentials have narrowed significantly, resulting in reduced opportunities to capture margins with our firm transportation and storage capacity. Additionally, price volatility in the natural gas markets remains relatively low compared with volatility in the past, which, coupled with a fairly flat forward price curve, reduces the value of the demand fee we receive for premium services and further limits opportunities to optimize our assets.

We have undertaken several steps to better align fixed costs with the current business environment, including allowing nonstrategic contracts to expire and attempting to renegotiate various natural gas storage and transportation contracts. Contract renegotiation activities that we have taken or expect to take include renewing contracts at current market rates at contract expiration or paying to terminate contracts in areas that are no longer strategic to our business. It is possible that we may recognize charges to our earnings as a result of certain of these actions. We expect these contractual changes to result in less storage and transportation capacity under lease. We also expect the reduction in our contracted natural gas transportation and storage capacity will reduce our operating costs and working-capital requirements.

Selected Financial Results - The following table sets forth certain selected financial results for our Energy Services segment for the periods indicated:



	Three Months Ended						Variances
	March 31,						2013 vs. 2012
Financial Results	2013			2012			Increase (Decrease)
	(Millions of dollars)
Revenues	$	547.6		$	460.8		$	86.8		19	%
Cost of sales and fuel	546.9			476.2			70.7			15	%
Net margin	0.7			(15.4		)	16.1			*
Operating costs	5.0			4.8			0.2			4	%
Depreciation and amortization	0.1			0.2			(0.1		)	(50	)%
Goodwill impairment	—			10.3			(10.3		)	(100	)%
Operating loss	$	(4.4	)	$	(30.7	)	$	26.3		86	%

* Percentage change is greater than 100 percent.

The following table sets forth our margins by activity for the periods indicated:



	Three Months Ended						Variances
	March 31,						2013 vs. 2012
	2013			2012			Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation revenues, gross	$	39.8		$	28.8		$	11.0		38	%
Storage and transportation costs	37.5			44.5			(7.0		)	(16	)%
Marketing, storage and transportation, net	2.3			(15.7		)	18.0			*
Financial trading, net	(1.6		)	0.3			(1.9		)	*
Net margin	$	0.7		$	(15.4	)	$	16.1		*

* Percentage change is greater than 100 percent.

Marketing, storage and transportation revenues, gross, include marketing, purchases and sales, premium services and the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Storage and transportation costs include the cost of leasing capacity, storage injection and withdrawal fees, fuel charges and gathering fees. Risk management and operational decisions have an impact on the net result of our marketing, premium-services and storage activities. These decisions can benefit margins in one line of business while decreasing margins in another. We evaluate our strategies on an ongoing basis to optimize the value of our contracted capacity and to minimize the financial impact of market conditions on the services we provide. While the financial impact of risk management and operational decisions on our overall business activities could be minimal, the impact to varying lines of business could be significant.

The decrease in our storage and transportation costs for the three months ended March 31, 2013, compared with the same period last year, reflects reduced transportation and storage contracted capacity.

For additional information on transportation and storage capacity refer to “Selected Operating Information” below.

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Financial trading, net, includes activities that are executed generally using financially settled derivatives. These activities are normally short term in nature, with a focus on capturing short-term price volatility. Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.

Revenues and cost of sales and fuel have increased for the three months ended March 31, 2013, compared with the same period last year, due primarily to higher natural gas prices, offset partially by lower sales volumes.

For the three months ended March 31, 2013, we realized $19.6 million in premium-services margins, and our storage and marketing margins consisted of $16.1 million from realized seasonal price differentials and marketing optimization activities and $21.7 million of storage demand costs. Our first-quarter 2013 combined premium-services and storage and marketing results were higher than the same period in 2012 when we realized $25.2 million in premium-services margins; and our storage and marketing margins consisted of losses of $1.8 million from realized seasonal price differentials, marketing and optimization activities, and $23.5 million of storage-demand costs. In addition, we recognized a gain on the change in fair value of our nonqualifying economic storage hedges of $0.4 million for the three months ended March 31, 2013, compared with a loss of $2.1 million for the same period in 2012.

Our premium services in the first quarter 2013 were impacted negatively by market conditions. Our storage and marketing margins for the three months ended March 31, 2013, were higher than the same period in 2012, primarily due to a $29.9 million reclassification in the first quarter 2012 of deferred losses into earnings from accumulated other comprehensive income (loss) on certain financial contracts that were used to hedge forecasted purchases of natural gas in 2012.

For the three months ended March 31, 2013, we realized a loss in our financial trading margins of $1.6 million compared with a gain of $0.3 million for the same period in 2012.

For the three months ended March 31, 2013, we realized a loss in our transportation margins of $11.0 million, compared with a loss of $12.5 million for the same period in 2012, due primarily to reduced contracted transportation capacity, renegotiated transportation rates and the release of contracted transportation capacity to a third party, resulting in the recognition of a loss in the first quarter 2012. Our transportation business continues to be impacted by narrow price location differentials and the inability to hedge at levels that were available to us in prior years. As a result of significant increases in the supply of natural gas, primarily from shale gas production across North America and new pipeline infrastructure projects, location and seasonal price differentials narrowed significantly beginning in 2010 and continuing through the three months ended March 31, 2013. This market change resulted in our transportation contracts being unprofitable, impacting our ability to recover our fixed costs.

We also recognized an expense of $10.3 million related to the impairment of our goodwill in the first quarter 2012. Given the significant decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment in the first quarter 2012 that reduced our goodwill balance to zero.

Selected Operating Information - The following table sets forth certain selected operating information for our Energy Services segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information	2013		2012
Natural gas marketed (Bcf)	202		218
Natural gas gross margin ($/Mcf)	$	0.01	$	(0.07	)
Physically settled volumes (Bcf)	369		417

Natural gas volumes marketed and physically settled volumes decreased for the three months ended March 31, 2013, compared with the same period last year, due primarily to decreased marketing activities. Transportation capacity in certain markets was not utilized due to the unfavorable economics of the narrow location price differentials as a result of increased supply of natural gas, primarily from shale production, and increased pipeline capacity as a result of pipeline construction.

At March 31, 2013, our natural gas transportation capacity was 0.8 Bcf/d, of which 0.8 Bcf/d was contracted under long-term natural gas transportation contracts, compared with 1.1 Bcf/d of total capacity and 1.1 Bcf/d of long-term capacity at March 31, 2012. Approximately 120.6 MMcf/d, which represents 16 percent of our transportation capacity, expires by the end of 2013, and an additional 390.4 MMcf/d, which represents 51 percent of our transportation capacity, expires by the end of 2015.

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Our natural gas in storage at March 31, 2013, was 10.3 Bcf, compared with 41.5 Bcf at March 31, 2012. At March 31, 2013, our total natural gas storage capacity under lease was 53.4 Bcf, compared with 75.6 Bcf at March 31, 2012. At March 31, 2013, our natural gas storage capacity under lease had a maximum withdrawal capability of 1.9 Bcf/d and maximum injection capability of 1.2 Bcf/d. Approximately 1.3 Bcf, which represents 2 percent of our storage capacity, expires by the end of 2013, and an additional 43.5 Bcf, which represents 81 percent of our storage capacity, expires by the end of 2015.

Reducing storage and transportation capacity continues to be a focus as we reduce fixed costs. It is possible that we may recognize charges to our earnings in the future as a result of these actions.

CONTINGENCIES

Gas Index Pricing Litigation - As previously reported, ONEOK and its subsidiary, ONEOK Energy Services Company L.P. (OESC), along with several other energy companies, are defending multiple lawsuits arising from alleged market manipulation or false reporting of natural gas prices to natural gas-index publications. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit reversed the summary judgments that had been granted in favor of ONEOK, OESC and other unaffiliated defendants in the following cases: Reorganized FLI, Learjet, Arandell, Heartland and NewPage. The Ninth Circuit also reversed the summary judgment that had been granted in favor of OESC on all state law claims asserted in the Sinclair case. The Ninth Circuit remanded the cases back to the United States District Court for the District of Nevada for further proceedings.

LIQUIDITY AND CAPITAL RESOURCES

General - ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and/or the issuance of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. Capital expenditures are funded by short- and long-term debt, issuances of equity and operating cash flow. We expect to continue to use these sources for our liquidity and capital resource needs. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings. We anticipate that our cash flow generated from operations, existing capital resources, ability to obtain financing and distributions from ONEOK Partners will enable us to maintain our current and planned level of operations and fund any share repurchases under our three-year, $750-million stock repurchase program. Should ONEOK need additional funding, it would fund additional capital needs with short- and long-term debt. ONEOK Partners anticipates that its cash flow generated from operations, sales of common units and existing capital resources and ability to obtain financing will enable it to maintain its current and planned level of operations. Additionally, ONEOK Partners expects to fund its future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

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Capitalization Structure - The following table sets forth ONEOK’s capital structure, excluding the debt of ONEOK Partners, for the periods indicated:



	March 31,	December 31,
	2013	2012
Long-term debt	45%	45%
ONEOK shareholders’ equity	55%	55%
Debt (including notes payable)	51%	54%
ONEOK shareholders’ equity	49%	46%

ONEOK, through its wholly owned subsidiary, ONEOK Partners GP, ONEOK Partners’ sole general partner, is responsible for directing the activities of ONEOK Partners, but ONEOK is not liable for, nor does it guarantee, any of ONEOK Partners’ liabilities. Likewise, ONEOK Partners is not liable for, nor does it guarantee, any of ONEOK’s liabilities. Significant legal and financial separations exist between ONEOK and ONEOK Partners. Additionally, for purposes of determining compliance with financial covenants in the ONEOK Credit Agreement, which are described below, the debt of ONEOK Partners is excluded.

The following table sets forth our consolidated capitalization structure at the dates indicated:



	March 31,	December 31,
	2013	2012
Long-term debt	61%	61%
Total equity	39%	39%
Debt (including notes payable)	63%	63%
Total equity	37%	37%

Stock Repurchase Program - Our three-year stock repurchase program was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. Following our $150 million repurchase in September 2012 and our $300 million repurchase in 2011, an additional $300 million may yet be purchased pursuant to our three-year repurchase program.

Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners and the issuance of commercial paper. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities and its commercial paper program. To the extent commercial paper is unavailable, ONEOK’s and ONEOK Partners’ respective revolving credit agreements may be utilized.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion. At March 31, 2013, ONEOK had $551.3 million of commercial paper outstanding, $1.9 million in letters of credit issued under the ONEOK Credit Agreement and approximately $75.0 million of cash and cash equivalents. ONEOK had approximately $646.8 million of credit

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available at March 31, 2013, under the ONEOK Credit Agreement. At March 31, 2013, ONEOK could have issued $2.6 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

Effective March 28, 2013, we amended the ONEOK Credit Agreement to extend its maturity to March 28, 2018, from April 5, 2016, and reduce the facility fee and interest-rate margins for any borrowings after the amendment’s effective date.

ONEOK Partners Credit Agreement - The ONEOK Partners 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 the ONEOK Partners 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 ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the quarter of the acquisition and the two following quarters. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK Partners Credit Agreement, if any, may become due and payable immediately. At March 31, 2013, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

The ONEOK Partners 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. The ONEOK Partners Credit Agreement is available to repay ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement.

The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $2.5 billion. At March 31, 2013, ONEOK Partners had no commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners Credit Agreement, approximately $68.9 million of cash and $1.2 billion of credit available under the ONEOK Partners Credit Agreement. At March 31, 2013, ONEOK Partners could have issued $2.4 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.

Other - Events in the European economy could impact European banks. Various European-based banks participate in the ONEOK Credit Agreement and ONEOK Partners Credit Agreement, representing an aggregate of $340 million and $342 million in committed capacity, respectively. 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 or ONEOK Partners under our respective credit agreements. Should any of these banks be unable to fund any future borrowings under the credit agreements, we believe other funding sources would likely be available to replace the European banks’ commitments.

Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, ONEOK expects to fund its longer-term cash requirements by issuing equity or long-term notes. ONEOK Partners expects to fund its 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, asset securitization and the sale and lease back of facilities.

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

ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022. The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million.

ONEOK Partners’ Debt Maturity - ONEOK Partners repaid its $350 million, 5.9-percent senior notes upon maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.

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ONEOK Partners’ Equity Issuance - ONEOK Partners has an “at-the-market” equity program for the offer and sale from time to time of its common units up to an aggregate amount of $300 million. The program allows ONEOK Partners to offer and sell its common units at prices ONEOK Partners deems 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 ONEOK Partners and the sales agent. ONEOK Partners is under no obligation to offer and sell common units under the program.

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

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $501.1 million and $348.4 million for the three months ending March 31, 2013 and 2012, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $443.5 billion and $280.8 million for the three months ended March 31, 2013 and 2012, respectively. 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 ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

The following table sets forth our 2013 projected capital expenditures, excluding AFUDC:



2013 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	2,640
Natural Gas Distribution	286
Other	30
Total projected capital expenditures	$	2,956

Credit Ratings - Our credit ratings at March 31, 2013, are shown in the table below:



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

ONEOK’s and ONEOK Partners’ commercial paper programs are each rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which currently are investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pre-tax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners currently do not anticipate their respective credit ratings to be downgraded; however, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under their respective commercial paper programs and credit agreements would increase, and ONEOK or ONEOK Partners potentially could lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK Credit Agreement, which expires in March 2018. In the event that ONEOK Partners is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK Partners would continue to have access to the ONEOK Partners Credit Agreement, which expires in August 2017. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement.

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Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. A decline in ONEOK’s credit rating below investment grade also may impact significantly other business segments.

In the normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide secured and unsecured credit. In the event of a downgrade in ONEOK’s or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners 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.

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 ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity-price volatility. See Note D of the Notes to Consolidated Financial Statements; the discussion under ONEOK Partners’ “Commodity-Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations; and Energy Services’ discussion under “Commodity-Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note M of the Notes to Consolidated Financial Statements in our Annual Report. See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period.

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	$	471.5		$	426.1		$	45.4
Investing activities	(494.8		)	(314.4		)	(180.4		)
Financing activities	(416.4		)	594.7			(1,011.1		)
Change in cash and cash equivalents	(439.7		)	706.4			(1,146.1		)
Change in cash and cash equivalents included in discontinued operations	—			8.8			(8.8		)
Change in cash and cash equivalents from continuing operations	(439.7		)	715.2			(1,154.9		)
Cash and cash equivalents at beginning of period	583.6			66.0			517.6
Cash and cash equivalents at end of period	$	143.9		$	781.2		$	(637.3	)

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 increased competition from other service providers, could affect our earnings and operating cash flows.

Cash flows from operating activities, before changes in operating assets and liabilities, were approximately $327.1 million for the three months ended March 31, 2013, compared with $400.0 million for the same period in 2012. The decrease was due primarily to changes in net margin and operating expenses as discussed in “Financial Results and Operating Information.”

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The changes in operating assets and liabilities in operating cash flows were approximately $144.4 million for the three months ended March 31, 2013, compared with $26.1 million for the same period in 2012. The increase was due primarily to the settlement of interest-rate swaps associated with ONEOK’s $700 million debt issuance in January 2012; the change was also impacted by the collection and payment of trade receivables and payables, resulting from the timing of cash collections from customers and paid to vendors and suppliers, which vary from period to period.

Investing Cash Flows - The change in cash flows from investing activities for the three months ended March 31, 2013, compared with the same period in 2012, reflects increased capital expenditures due primarily to ONEOK Partners’ growth projects.

Financing Cash Flows - The change in cash flows from financing activities is the result of ONEOK’s January 2012 debt issuance and ONEOK Partners’ March 2012 equity issuances, as well as increased distributions to noncontrolling interests and increased dividends in the first quarter 2013, compared with the same period last year. Financing cash flows also reflect a slightly lower repayment of notes payable.

REGULATORY

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 ONEOK, 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.

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Natural Gas Distribution segment. See discussion of our Natural Gas Distribution segment’s regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ENVIRONMENTAL AND SAFETY MATTERS

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, emissions 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.

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

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•	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, and 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 emissions equivalents for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions and the emissions equivalents for all NGLs produced by ONEOK Partners 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 emissions data did not have, and we do not expect 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.

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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 current 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.

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) who 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 enhancements cost to have a material impact on our results of operations, financial position or cash flows.

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

Environmental Footprint - Our environmental and climate change strategy focuses on minimizing 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 voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report.

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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 estimates and critical accounting policies 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, including energy sales and 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 status of deregulation of retail natural gas distribution;


•	the capital intensive nature of our businesses;


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


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


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


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


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


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


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


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


•	the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in stock and bond market returns;

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


•	actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;


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


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


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


•	the risk that material weaknesses or significant deficiencies in our internal controls 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 or 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;


•	adverse labor relations;


•	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 possible loss of natural gas distribution franchises or other adverse effects caused by the actions of municipalities;


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


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


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


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


•	the impact of potential impairment charges;


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


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


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

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in 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.

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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 D of the Notes to Consolidated Financial Statements and the discussion under ONEOK Partners’ “Commodity-Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.

Energy Services

Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk-management assets and liabilities, excluding $2.2 million and $27.4 million of net assets at March 31, 2013, and December 31, 2012, respectively, from derivative instruments designated as either fair value or cash flow hedges for the periods indicated:



Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2012	$	5,033
Derivatives reclassified or otherwise settled during the period	(2,343		)
Fair value of new derivatives entered into during the period	(976		)
Other changes in fair value	(53		)
Net fair value of derivatives outstanding at March 31, 2013 (a)	$	1,661

(a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $1.6 million matures through March 2014 and $0.1 million matures through March 2015.

The change in the net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities.

For further discussion of fair value measurements and derivative instruments, see the “Estimates and Critical Accounting Policies” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in our Annual Report. Also, see Notes C and D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Value-at-Risk (VAR) Disclosure of Commodity-Price Risk - The potential impact on our future earnings, as measured by VAR, was $1.6 million and $1.9 million at March 31, 2013 and 2012, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:



	Three Months Ended
	March 31,
Value-at-Risk	2013		2012
	(Millions of dollars)
Average	$	1.8	$	2.4
High	$	2.7	$	3.0
Low	$	1.4	$	1.9

Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in our portfolio during the year. The decrease in average VAR for March 31, 2013, compared with March 31, 2012, was due primarily to a decrease in total transportation capacity over the five-year period that VAR is calculated.

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To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk-management decisions may have on our business, operating results or financial position.

INTEREST-RATE RISK

We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. At March 31, 2013, the interest rate on all of ONEOK’s and ONEOK Partners’ long-term debt was fixed, and ONEOK Partners had forward-starting interest-rate swaps that have been designated as cash flow hedges of the variability of interest payments on a portion of a forecasted debt issuance 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 - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) 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 Rules 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 provided in Note M, “Gas Index Pricing Litigation,” of the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report. Additional information about our legal proceedings is included under Part 1, 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.


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

The following table sets forth information relating to our purchases of our common stock for the periods indicated:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number(or Approximate Dollar Value) of Shares (or Units) that May Be Purchased Under the Plans or Programs
January 1-31, 2013	—	$	—	—
February 1-28, 2013	—	$	—	—
March 1-31, 2013	—	$	—	—
Total	—	$	—	—	$	300,000,000	(a)

(a) - The maximum approximate dollar value of shares that may yet be purchased pursuant to our approximately $750 million stock repurchase program that was announced on October 21, 2010, subject to the limitations that purchases will not exceed $300 million in any one calendar year. The program will terminate upon the completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first.

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ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not Applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.


ITEM 5.	OTHER INFORMATION

Not Applicable.


ITEM 6.	EXHIBITS

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

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



Exhibit No.		Exhibit Description

	10.1	Amendment No. 1 to the Equity Distribution Agreement dated January 13, 2013, by and between 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 January 23, 2013 (File No. 1-12202)).

	10.2	Form of Restricted Unit Stock Bonus Award Agreement dated February 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed February 22, 2013 (File No. 1-13643)).

	10.3	Form of Performance Unit Award Agreement dated February 20, 2013 (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form 8-K filed February 22, 2013 (File No. 1-13643)).

	10.4	First Amendment to Credit Agreement, dated as of March 28, 2013, among ONEOK, Inc., as borrower, the lenders party thereto, Bank of America, N.A., as administrative agent, swing line lender, and a letter of credit issuer, and JPMorgan Chase Bank, N.A. and The Royal Bank of Scotland plc, as letter of credit issuers (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed April 2, 2013 (File No. 1-13643)).

	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 to Consolidated Financial Statements.

We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

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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 thereunto duly authorized.



	ONEOK, Inc.
	Registrant


Date: May 1, 2013	By:	/s/ Derek S. Reiners
		Derek S. Reiners
		Senior Vice President,
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)