ONEOK (OKE) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

X  Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2013.

OR

___ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from __________ to __________.

Commission file number   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 October 29, 2013, the Company had 206,286,720 shares of common stock outstanding.

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ONEOK, Inc.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2013 and 2012	6
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2013 and 2012	7
	Consolidated Balance Sheets - September 30, 2013, and December 31, 2012	8
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2013 and 2012	11
	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2013	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	67
Part II.	Other Information
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3.	Defaults Upon Senior Securities	67
Item 4.	Mine Safety Disclosures	67
Item 5.	Other Information	67
Item 6.	Exhibits	68
Signature		70

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.
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
MDth/d	Thousand dekatherms per day
MMBbl	Million barrels
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
ONE Gas	ONE Gas, Inc.
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.
ONEOK Partners Credit Agreement	ONEOK Partners’ $1.2 billion revolving credit agreement dated August 1, 2011, as amended

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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
RRC	Railroad Commission of Texas
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Viking Gas Transmission	Viking Gas Transmission Company
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2013			2012			2013			2012
	(Thousands of dollars, except per share amounts)
Revenues	$	3,571,925		$	3,028,775		$	10,462,606		$	8,972,635
Cost of sales and fuel	3,010,737			2,474,803			8,824,577			7,226,114
Net margin	561,188			553,972			1,638,029			1,746,521
Operating expenses
Operations and maintenance	209,019			206,048			635,915			603,055
Depreciation and amortization	94,267			81,434			276,343			249,429
Goodwill impairment	—			—			—			10,255
General taxes	27,843			23,157			94,000			81,471
Total operating expenses	331,129			310,639			1,006,258			944,210
Gain (loss) on sale of assets	22			(420		)	342			603
Operating income	230,081			242,913			632,113			802,914
Equity earnings from investments (Note L)	27,468			28,591			79,744			92,380
Allowance for equity funds used during construction	6,429			3,302			21,172			6,126
Other income	6,154			5,049			16,652			11,495
Other expense	(1,077		)	(919		)	(4,479		)	(3,990		)
Interest expense (net of capitalized interest of $14,704, $11,802, $39,203 and $30,521, respectively)	(81,908		)	(71,364		)	(244,076		)	(218,714		)
Income before income taxes	187,147			207,572			501,126			690,211
Income taxes	(39,449		)	(42,584		)	(108,228		)	(156,835		)
Income from continuing operations	147,698			164,988			392,898			533,376
Income from discontinued operations, net of tax (Note C)	—			—			—			762
Gain on sale of discontinued operations, net of tax (Note C)	—			—			—			13,517
Net income	147,698			164,988			392,898			547,655
Less: Net income attributable to noncontrolling interests	85,342			99,769			217,102			298,578
Net income attributable to ONEOK	$	62,356		$	65,219		$	175,796		$	249,077
Amounts attributable to ONEOK:
Income from continuing operations	$	62,356		$	65,219		$	175,796		$	234,798
Income from discontinued operations	—			—			—			14,279
Net income	$	62,356		$	65,219		$	175,796		$	249,077
Basic earnings per share:
Income from continuing operations (Note J)	$	0.30		$	0.32		$	0.85		$	1.14
Income from discontinued operations	—			—			—			0.07
Net income	$	0.30		$	0.32		$	0.85		$	1.21
Diluted earnings per share:
Income from continuing operations (Note J)	$	0.30		$	0.31		$	0.84		$	1.11
Income from discontinued operations	—			—			—			0.07
Net income	$	0.30		$	0.31		$	0.84		$	1.18
Average shares (thousands)
Basic	206,235			205,005			205,952			206,638
Diluted	209,893			209,960			209,408			211,198
Dividends declared per share of common stock	$	0.38		$	0.33		$	1.10		$	0.94

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2013			2012			2013			2012
	(Thousands of dollars)
Net income	$	147,698		$	164,988		$	392,898		$	547,655
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management assets/liabilities, net of tax of $(467), $12,244, $(10,349) and $(2,146), respectively	(2,542		)	(30,383		)	37,095			4,520
Realized (gains) losses in net income, net of tax of $333, $6,143, $(1,748) and $12,954 respectively	789			(20,973		)	4,694			(44,675		)
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $277, $(57), $147 and $(132), respectively	(440		)	90			(234		)	210
Change in pension and postretirement benefit plan liability, net of tax of $4,603, $3,644, $13,651 and $10,932, respectively	(7,293		)	(5,778		)	(21,637		)	(17,330		)
Total other comprehensive income (loss), net of tax	(9,486		)	(57,044		)	19,918			(57,275		)
Comprehensive income	138,212			107,944			412,816			490,380
Less: Comprehensive income attributable to noncontrolling interests	83,378			77,561			239,714			275,658
Comprehensive income attributable to ONEOK	$	54,834		$	30,383		$	173,102		$	214,722

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2013		2012
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	779,524	$	583,618
Accounts receivable, net	1,166,994		1,349,371
Gas and natural gas liquids in storage	664,213		517,014
Commodity imbalances	94,404		90,211
Energy marketing and risk-management assets (Notes D and E)	16,437		48,577
Other current assets	160,452		175,869
Total current assets	2,882,024		2,764,660
Property, plant and equipment
Property, plant and equipment	14,944,162		13,088,991
Accumulated depreciation and amortization	3,173,366		2,974,651
Net property, plant and equipment	11,770,796		10,114,340
Investments and other assets
Investments in unconsolidated affiliates (Note L)	1,201,873		1,221,405
Goodwill and intangible assets	990,456		996,206
Other assets	765,194		758,664
Total investments and other assets	2,957,523		2,976,275
Total assets	$	17,610,343	$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Continued)
	September 30,			December 31,
(Unaudited)	2013			2012
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	10,656		$	10,855
Notes payable (Note F)	562,329			817,170
Accounts payable	1,382,785			1,333,489
Commodity imbalances	227,355			272,436
Energy marketing and risk-management liabilities (Notes D and E)	5,530			9,990
Other current liabilities	433,055			369,054
Total current liabilities	2,621,710			2,812,994
Long-term debt, excluding current maturities (Note G)	7,757,159			6,515,372
Deferred credits and other liabilities
Deferred income taxes	1,776,949			1,592,802
Other deferred credits	763,879			701,657
Total deferred credits and other liabilities	2,540,828			2,294,459
Commitments and contingencies (Note N)
Equity (Note H)
ONEOK shareholders’ equity:
Common stock, $0.01 par value: authorized 600,000,000 shares; issued 245,811,180 shares and outstanding 206,273,200 shares at September 30, 2013; issued 245,811,180 shares and outstanding 204,935,043 shares at December 31, 2012	2,458			2,458
Paid-in capital	1,404,086			1,324,698
Accumulated other comprehensive loss (Note I)	(219,492		)	(216,798		)
Retained earnings	2,008,471			2,059,024
Treasury stock, at cost: 39,537,980 shares at September 30, 2013, and 40,876,137 shares at December 31, 2012	(1,005,829		)	(1,039,773		)
Total ONEOK shareholders’ equity	2,189,694			2,129,609
Noncontrolling interests in consolidated subsidiaries	2,500,952			2,102,841
Total equity	4,690,646			4,232,450
Total liabilities and equity	$	17,610,343		$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2013			2012
	(Thousands of dollars)
Operating activities
Net income	$	392,898		$	547,655
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	276,343			249,437
Charges attributable to exit activities, net of settlements	124,610			—
Impairment of goodwill	—			10,255
Gain on sale of discontinued operations	—			(13,517		)
Reclassified loss on energy price risk-management assets and liabilities	—			29,861
Equity earnings from investments	(79,744		)	(92,380		)
Distributions received from unconsolidated affiliates	79,022			92,996
Deferred income taxes	107,575			170,657
Share-based compensation expense	27,634			35,970
Allowance for equity funds used during construction	(21,172		)	(6,126		)
Gain on sale of assets	(342		)	(603		)
Other	(4,047		)	(1,770		)
Changes in assets and liabilities:
Accounts receivable	182,377			350,350
Gas and natural gas liquids in storage	(147,199		)	(94,362		)
Accounts payable	82,743			(156,483		)
Commodity imbalances, net	(49,274		)	17,310
Energy marketing and risk-management assets and liabilities	(15,574		)	(205,008		)
Other assets and liabilities, net	65,696			(171,383		)
Cash provided by operating activities	1,021,546			762,859
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(1,597,820		)	(1,238,908		)
Acquisition	(304,889		)	—
Proceeds from sale of discontinued operations, net of cash sold	—			32,946
Contributions to unconsolidated affiliates	(4,558		)	(21,284		)
Distributions received from unconsolidated affiliates	24,891			25,756
Proceeds from sale of assets	1,685			1,918
Other	—			988
Cash used in investing activities	(1,880,691		)	(1,198,584		)
Financing activities
Borrowing of notes payable, net	(254,841		)	(165,235		)
Issuance of debt, net of discounts	1,247,822			1,994,693
Long-term debt financing costs	(10,217		)	(15,030		)
Repayment of debt	(5,802		)	(359,251		)
Repurchase of common stock	—			(150,000		)
Issuance of common stock	8,538			7,068
Issuance of common units, net of issuance costs	569,246			459,680
Dividends paid	(226,349		)	(194,443		)
Distributions to noncontrolling interests	(273,346		)	(237,744		)
Cash provided by financing activities	1,055,051			1,339,738
Change in cash and cash equivalents	195,906			904,013
Change in cash and cash equivalents included in discontinued operations	—			8,859
Change in cash and cash equivalents from continuing operations	195,906			912,872
Cash and cash equivalents at beginning of period	583,618			65,953
Cash and cash equivalents at end of period	$	779,524		$	978,825

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)	—	—		—			(2,694		)
Common stock issued	—	—		(22,052		)	—
Common stock dividends - $1.10 per share	—	—		—			—
Issuance of common units of ONEOK Partners	—	—		84,458			—
Distributions to noncontrolling interests	—	—		—			—
Other	—	—		16,982			—
September 30, 2013	245,811,180	$	2,458	$	1,404,086		$	(219,492	)

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	175,796			—			217,102			392,898
Other comprehensive income (loss)	—			—			22,612			19,918
Common stock issued	—			33,944			—			11,892
Common stock dividends - $1.10 per share	(226,349		)	—			—			(226,349		)
Issuance of common units of ONEOK Partners	—			—			431,743			516,201
Distributions to noncontrolling interests	—			—			(273,346		)	(273,346		)
Other	—			—			—			16,982
September 30, 2013	$	2,008,471		$	(1,005,829	)	$	2,500,952		$	4,690,646

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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 and nine months ended September 30, 2013, are not necessarily indicative of the results that may be expected for a 12-month period.

On July 25, 2013, we announced that our Board of Directors unanimously authorized management to pursue a plan to separate our natural gas distribution business into a standalone publicly traded company. The natural gas distribution company, named ONE Gas will consist of ONEOK’s Natural Gas Distribution segment that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.

ONEOK and its subsidiaries will continue to be the sole general partner and own limited partner units of ONEOK Partners (NYSE: OKS), which represented a 41.3 percent interest in ONEOK Partners at September 30, 2013, and operate our Energy Services segment through the completion of the wind down process.  Under the separation plan, ONEOK shareholders will retain their current shares of ONEOK stock and receive a pro-rata dividend of shares of stock in ONE Gas in a transaction that is expected to be tax-free to ONEOK and its shareholders. The plan provides for the completion of the separation after the receipt of regulatory approvals. On October 1, 2013, ONE Gas filed a registration statement on Form 10 with the SEC. Our Board of Directors retains the discretion to determine whether and when to complete the separation.

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

Recently Issued Accounting Standards Update -In July 2013, the FASB issued ASU 2013-10, “Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes,” which allows an entity to designate the Fed Funds Effective Swap rate (also known as the Overnight Index Swap rate, or OIS rate, in the United States) as a benchmark interest rate for hedge accounting purposes in addition to the interest rates on direct Treasury obligations of the United States government and LIBOR. In addition, this guidance removes the restriction on using different benchmark interest rates for similar hedges. This guidance is effective prospectively for qualifying new or redesigned hedging relationships entered into on or after July 17, 2013. We adopted this guidance with our September 30, 2013, Quarterly Report, and it did not impact materially our financial position or results of operations. See Notes D and E for additional disclosures.

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 our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note I 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 our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note D 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

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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 adopted this guidance for our annual assessments beginning in July 2013, and it did not impact our financial position or results of operations.

Impairment of Goodwill and Indefinite-lived Intangible Assets - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually as of July 1. At July 1, 2013, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than its carrying amount and to determine whether it was more likely than not that the indefinite-lived intangible asset was impaired.  After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.

B. EXIT ACTIVITIES

In June 2013, we announced we would exit the operations of our Energy Services segment through an accelerated wind down process. Our Energy Services segment faced challenging industry conditions that showed no signs of improving. Increased natural gas supply and infrastructure, coupled with lower natural gas price volatility, narrowed seasonal and location natural gas price differentials, which resulted in limited opportunities to generate revenues to cover our fixed costs on our contracted storage and transportation capacity. We executed agreements in 2013 to release a significant portion of our nonaffiliated, third-party natural gas transportation and storage contracts to third parties effective July 1 and September 1, 2013, at current market rates that resulted in noncash charges totaling $130.2 million. In addition, pursuant to a request for proposal, our Energy Services segment assigned contracts for 18.0 Bcf of affiliated storage capacity to our Natural Gas Distribution segment in June 2013. Our Energy Services segment will continue to serve its contracted premium-services customers during the wind down, and we expect the Energy Services segment to be classified as discontinued operations, effective April 1, 2014, when substantially all operations of the segment have ceased.

The following table summarizes the change in our liability related to released capacity contracts for the period indicated:

	Three Months Ended
	September 30, 2013
	(Millions of dollars)
Beginning balance	$	113.8
Noncash charges	16.4
Settlements	(6.2		)
Accretion	0.6
Ending balance	$	124.6

We recorded these noncash charges in cost of sales and fuel in our Consolidated Statements of Income. We expect to record additional noncash charges of approximately $12 million before taxes between October 1, 2013, and March 31, 2014, subject to the release or assignment of the additional natural gas transportation, storage and other energy contracts. We do not expect the total charge attributable to any severance benefits will be material. We expect future cash payments associated with released transportation and storage capacity from the wind down of our Energy Services segment to total approximately $89 million on an after-tax basis with approximately $8 million paid in the fourth quarter 2013, $33 million in 2014, $24 million in 2015 and $24 million over the period 2016 through 2023.

C. 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.

D. 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

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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:

	September 30, 2013
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	50,965		$	1,790		$	8,707		$	61,462		$	(46,938	)	$	14,524
Physical contracts	—			1,122			3,205			4,327			(541		)	3,786
Interest-rate contracts	—			43,614			—			43,614			—			43,614
Total derivatives	50,965			46,526			11,912			109,403			(47,479		)	61,924
Trading securities (b)	10,193			—			—			10,193			—			10,193
Available-for-sale investment securities (c)	1,478			—			—			1,478			—			1,478
Total assets	$	62,636		$	46,526		$	11,912		$	121,074		$	(47,479	)	$	73,595
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(26,355	)	$	(1,207	)	$	(7,679	)	$	(35,241	)	$	32,981		$	(2,260	)
Physical contracts	—			(267		)	(3,571		)	(3,838		)	541			(3,297		)
Total derivatives	(26,355		)	(1,474		)	(11,250		)	(39,079		)	33,522			(5,557		)
Fair value of firm commitments (d)	—			—			(144		)	(144		)	—			(144		)
Total liabilities	$	(26,355	)	$	(1,474	)	$	(11,394	)	$	(39,223	)	$	33,522		$	(5,701	)

(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 September 30, 2013, we held $14.0 million of cash collateral and posted no cash collateral with various counterparties.

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

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

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

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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 posted $4.5 million of cash collateral with various counterparties.

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

(c) - Included in our Consolidated Balance Sheets as other 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 NGLs.  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)
July 1, 2013	$	8,015		$	—		$	8,015
Total realized/unrealized gains (losses):
Included in earnings (a)	(215		)	(144		)	(359		)
Included in other comprehensive income (loss)	(7,162		)	—			(7,162		)
Transfers into Level 3	24			—			24
September 30, 2013	$	662		$	(144	)	$	518
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 September 30, 2013 (a)	$	367		$	(42	)	$	325

(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)
July 1, 2012	$	37,745		$	(4,250	)	$	33,495
Total realized/unrealized gains (losses):
Included in earnings (a)	(4,366		)	2,083			(2,283		)
Included in other comprehensive income (loss)	(20,295		)	—			(20,295		)
Transfers into Level 3	385			—			385
Transfers out of Level 3	685			—			685
September 30, 2012	$	14,154		$	(2,167	)	$	11,987
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 September 30, 2012 (a)	$	51		$	205		$	256

(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, 2013	$	1,683		$	(1,280	)	$	403
Total realized/unrealized gains (losses):
Included in earnings (a)	(4,343		)	1,136			(3,207		)
Included in other comprehensive income (loss)	3,487			—			3,487
Transfers out of Level 3	(165		)	—			(165		)
September 30, 2013	$	662		$	(144	)	$	518
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 September 30, 2013 (a)	$	(760	)	$	21		$	(739	)

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

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	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)	(13,153		)	5,116			(8,037		)
Included in other comprehensive income (loss)	6,384			—			6,384
Sale of discontinued operations	(3,636		)	—			(3,636		)
Transfers out of Level 3	(545		)	—			(545		)
September 30, 2012	$	14,154		$	(2,167	)	$	11,987
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 September 30, 2012 (a)	$	352		$	(296	)	$	56

(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 September 30, 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 $8.1 billion at September 30, 2013, and $7.5 billion at December 31, 2012.  The book value of long-term debt, including current maturities, was $7.8 billion at September 30, 2013, and $6.5 billion at 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.

E. 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. In June 2013, we announced we will exit the operations of our Energy Services segment. As a result, the use of derivative instruments will decrease significantly within our Energy Services segment. See Note B for additional information. 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; 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.

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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 rates; and

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

With respect to the net open positions that exist within our marketing 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. 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 September 30, 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.

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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.

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.

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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:

	September 30, 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	$	33,216	(b)	$	(4,554	)	$	47,516	(c)	$	(4,885	)
Physical contracts	351			(2,711		)	56			(126		)
Interest-rate contracts	43,614			—			10,923			—
Total derivatives designated as hedging instruments	77,181			(7,265		)	58,495			(5,011		)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts	12,260			(15,018		)	24,970			(25,009		)
Physical contracts	3,976			(1,127		)	4,059			(153		)
Trading instruments
Financial contracts	15,986			(15,669		)	15,358			(14,192		)
Total derivatives not designated as hedging instruments	32,222			(31,814		)	44,387			(39,354		)
Total derivatives	$	109,403		$	(39,079	)	$	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 $8.0 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).

(c) - 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 periods indicated:

		September 30, 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	—		(72.4		)	—		(85.1		)
- Crude oil and NGLs (MMbbl)	Futures, forwards and swaps	—		(2.3		)	—		(1.1		)
Basis
- Natural gas (Bcf)	Futures, forwards and swaps	—		(58.0		)	—		(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	5.8		(5.8		)	59.1		(59.1		)
Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Futures, forwards and swaps	53.0		(53.1		)	60.7		(60.4		)
	Options	—		—			102.1		(100.8		)
Basis
- Natural gas (Bcf)	Futures, forwards and swaps	105.9		(105.7		)	80.2		(81.7		)
Index
- Natural gas (Bcf)	Futures, forwards and swaps	8.2		(4.8		)	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 September 30, 2013, includes gains of approximately $5.6 million, net of tax, related to these hedges that will be recognized within the next 27 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $3.6 million in net gains over the next 12 months and net gains of $2.0 million thereafter.  The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $50.9 million, net of tax, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $5.3 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 nine months ended September 30, 2013, cost of sales and fuel in our Consolidated Statements of Income includes $10.1 million reflecting an adjustment to natural gas inventory at the lower of cost or market value. We reclassified $8.0 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

For the nine months ended September 30, 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

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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.

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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
	(Thousands of dollars)
Commodity contracts	$	(8,796	)	$	(41,452	)	$	11,718	$	39,461
Interest-rate contracts	6,721			(1,175		)	35,726		(32,795		)
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(2,075	)	$	(42,627	)	$	47,444	$	6,666

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

Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from  Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
		(Thousands of dollars)
Commodity contracts	Revenues	$	3,357		$	31,447		$	18,718		$	127,477
Commodity contracts	Cost of sales and fuel	(117		)	(2,503		)	(14,320		)	(65,940		)
Interest-rate contracts	Interest expense	(3,696		)	(1,828		)	(10,840		)	(3,908		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(456	)	$	27,116		$	(6,442	)	$	57,629

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 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 and nine months ended September 30, 2013, we recorded immaterial gains due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable. For the three and nine months ended September 30, 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						Nine Months Ended
		September 30,						September 30,
		2013				2012		2013				2012
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	4			$	867	$	(2,054	)		$	1,673
Commodity contracts - nontrading (a)	Cost of sales and fuel	(534		)	(b)	601		(2,959		)	(b)	4,924
Total gain (loss) recognized in income on derivatives		$	(530	)		$	1,468	$	(5,013	)		$	6,597

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

(b) - Includes losses of $0.4 million and $2.2 million for the three and nine months ended September 30, 2013, respectively, on certain derivatives derecognized that were designated previously as fair value hedges of firm transportation commitments that no longer meet the definition of a firm commitment.

Our Natural Gas Distribution segment held natural gas call options with fair values of $4.8 million and $1.8 million at September 30, 2013, and December 31, 2012, respectively.  The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism.  For the three and nine months ended September 30, 2013, we recorded losses of $2.3 million and $7.4 million, respectively, which are deferred as part of our unrecovered purchased-gas costs. For the three and nine months ended September 30, 2012, we recorded gains of $2.8 million and $3.8 million, respectively, which are deferred as part of our unrecovered purchased-gas costs.

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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. The change in fair value of derivatives designated as fair value hedges and the related hedged firm commitments and the ineffectiveness related to these hedges were not material for the three and nine months ended September 30, 2013 and 2012.

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 September 30, 2013, was $2.5 million.

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 September 30, 2013, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.

F. 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 September 30, 2013, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 48.2 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. Based on our current credit rating, borrowings, if any, will accrue at LIBOR plus 117.5 basis points, and the annual facility fee is 20 basis points.

At September 30, 2013, ONEOK had $515.3 million of commercial paper outstanding and $1.9 million in letters of credit issued, leaving approximately $682.8 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

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(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.  As a result of ONEOK Partners’ Sage Creek acquisition on September 30, 2013, its allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 for the current quarter and will remain at that level through the first quarter 2014. 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 September 30, 2013, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.2 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, including repayment of 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.  At September 30, 2013, ONEOK Partners had $47.0 million in 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. Based on ONEOK Partners’ current credit rating, borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points. 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 of unaffiliated parties. ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners, and ONEOK Partners does not guarantee the debt, commercial paper or other similar commitments of ONEOK.

G. LONG-TERM DEBT

In September 2013, ONEOK Partners completed an underwritten public offering of $1.25 billion of senior notes, consisting of $425 million, 3.2-percent senior notes due 2018, $425 million, 5.0-percent senior notes due 2023 and $400 million, 6.2-percent senior notes due 2043. A portion of the net proceeds from the offering of approximately $1.24 billion was used to repay amounts outstanding under its commercial paper program, and the balance will be used for general partnership purposes, including but not limited to capital expenditures.

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

ONEOK Partners may redeem its 3.2 percent senior notes due 2018, its 5.0 percent senior notes due 2023, and its 6.2 percent senior notes due 2043 from the September 2013 offering at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates.  Prior to these dates, ONEOK Partners may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any ONEOK Partners’ nonguarantor subsidiaries.

In September 2012, ONEOK Partners completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0 percent senior notes due 2017 and $900 million, 3.375 percent senior notes due 2022. A portion of the net

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proceeds from the offering of approximately $1.29 billion was used to repay amounts outstanding under its commercial paper program, and the balance was used for general partnership purposes, including but not limited to capital expenditures.

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.

H. 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
	September 30, 2013									September 30, 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	$	2,085,349		$	2,089,007		$	4,174,356		$	2,089,540		$	2,116,448		$	4,205,988
Net income	62,356			85,342			147,698			65,219			99,769			164,988
Other comprehensive income (loss)	(7,522		)	(1,964		)	(9,486		)	(34,836		)	(22,208		)	(57,044		)
Repurchase of common stock	—			—			—			—			—			—
Common stock issued	4,142			—			4,142			3,838			—			3,838
Common stock dividends	(78,367		)	—			(78,367		)	(67,671		)	—			(67,671		)
Issuance of common units of ONEOK Partners	81,502			420,391			501,893			—			—			—
Distributions to noncontrolling interests	—			(91,824		)	(91,824		)	—			(84,156		)	(84,156		)
Other	42,234			—			42,234			9,616			—			9,616
Ending balance	$	2,189,694		$	2,500,952		$	4,690,646		$	2,065,706		$	2,109,853		$	4,175,559

	Nine Months Ended									Nine Months Ended
	September 30, 2013									September 30, 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	175,796			217,102			392,898			249,077			298,578			547,655
Other comprehensive income (loss)	(2,694		)	22,612			19,918			(34,355		)	(22,920		)	(57,275		)
Repurchase of common stock	—			—			—			(150,000		)	—			(150,000		)
Common stock issued	11,892			—			11,892			10,390			—			10,390
Common stock dividends	(226,349		)	—			(226,349		)	(194,443		)	—			(194,443		)
Issuance of common units of ONEOK Partners	84,458			431,743			516,201			(51,100		)	510,780			459,680
Distributions to noncontrolling interests	—			(273,346		)	(273,346		)	—			(237,744		)	(237,744		)
Other	16,982			—			16,982			(2,436		)	—			(2,436		)
Ending balance	$	2,189,694		$	2,500,952		$	4,690,646		$	2,065,706		$	2,109,853		$	4,175,559

Dividends - Dividends paid on our common stock to shareholders of record at the close of business on January 31, 2013, April 30, 2013, and August 5, 2013 were $0.36 per share, $0.36 per share, and $0.38 per share respectively.  A dividend of $0.38 per share was declared for shareholders of record on November 4, 2013, payable November 14, 2013.

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

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I. 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	16,406			(234		)	(56,164		)	(39,992		)
Amounts reclassified from accumulated other comprehensive income (loss)	2,771			—			34,527			37,298
Other comprehensive income (loss) attributable to ONEOK	19,177			(234		)	(21,637		)	(2,694		)
September 30, 2013	$	(35,853	)	$	800		$	(184,439	)	$	(219,492	)

(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 periods indicated:

Details about Accumulated Other Comprehensive Income (Loss) Components	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013			Affected Line Item in the Consolidated Statements of Income
	(Thousand of dollars)
Unrealized (gains) losses on energy marketing and risk-management assets/liabilities
Commodity contracts	$	(3,357	)	$	(18,718	)	Revenues
Commodity contracts	117			14,320			Cost of sales and fuel
Interest-rate contracts	3,696			10,840			Interest expense
	456			6,442			Income before income taxes
	333			(1,748		)	Income tax expense
	789			4,694			Net income
Noncontrolling interest	1,317			1,923			Less: Net income attributable to noncontrolling interest
	$	(528	)	$	2,771		Net income attributable to ONEOK
Pension and postretirement benefit plan obligations (a)
Amortization of net loss	$	19,729		$	59,183
Amortization of unrecognized prior service cost	(1,438		)	(4,314		)
Amortization of unrecognized net asset at adoption	71			213
Settlement charge	275			1,225
	18,637			56,307			Income before income taxes
	(7,210		)	(21,780		)	Income tax expense
	$	11,427		$	34,527		Net income attributable to ONEOK
Total reclassifications for the period attributable to ONEOK	$	10,899		$	37,298		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 K for additional detail of our net periodic benefit cost.

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J. 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 September 30, 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	$	62,356	206,235	$	0.30
Diluted EPS from continuing operations
Effect of dilutive securities	—		3,658
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	62,356	209,893	$	0.30

	Three Months Ended September 30, 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	$	65,219	205,005	$	0.32
Diluted EPS from continuing operations
Effect of dilutive securities	—		4,955
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	65,219	209,960	$	0.31

	Nine Months Ended September 30, 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	$	175,796	205,952	$	0.85
Diluted EPS from continuing operations
Effect of dilutive securities	—		3,456
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	175,796	209,408	$	0.84

	Nine Months Ended September 30, 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	$	234,798	206,638	$	1.14
Diluted EPS from continuing operations
Effect of dilutive securities	—		4,560
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	234,798	211,198	$	1.11

There were no option shares excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2013 and 2012.

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K. EMPLOYEE BENEFIT PLANS

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

	Pension Benefits						Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,735		$	5,325		$	17,207		$	15,975
Interest cost	13,612			14,809			40,836			44,427
Expected return on assets	(20,318		)	(20,689		)	(60,954		)	(62,067		)
Amortization of unrecognized prior service cost	230			242			690			726
Amortization of net loss	16,572			12,111			49,712			36,333
Settlement charge	275			—			1,225			—
Net periodic benefit cost	$	16,106		$	11,798		$	48,716		$	35,394

	Postretirement Benefits						Postretirement Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	1,145		$	1,239		$	3,435		$	3,716
Interest cost	2,910			3,473			8,732			10,419
Expected return on assets	(3,065		)	(2,671		)	(9,195		)	(8,013		)
Amortization of unrecognized net asset at adoption	71			718			213			2,154
Amortization of unrecognized prior service cost	(1,668		)	(2,063		)	(5,004		)	(6,189		)
Amortization of net loss	3,157			3,296			9,471			9,888
Net periodic benefit cost	$	2,550		$	3,992		$	7,652		$	11,975

L. 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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(Thousands of dollars)
Northern Border Pipeline	$	16,464	$	18,185	$	48,133	$	54,493
Overland Pass Pipeline Company	5,783		4,490		14,210		15,786
Fort Union Gas Gathering	2,946		4,091		9,895		11,494
Bighorn Gas Gathering	559		1,157		1,897		3,118
Other	1,716		668		5,609		7,489
Equity earnings from investments	$	27,468	$	28,591	$	79,744	$	92,380

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(Thousands of dollars)
Income Statement
Operating revenues	$	131,959	$	125,828	$	391,912	$	373,038
Operating expenses	$	63,971	$	60,937	$	189,366	$	173,232
Net income	$	61,630	$	55,721	$	185,580	$	180,787
Distributions paid to ONEOK Partners	$	34,409	$	34,557	$	103,913	$	118,752

ONEOK and ONEOK Partners incurred expenses in transactions with unconsolidated affiliates of $15.9 million and $9.0 million for the three months ended September 30, 2013 and 2012, respectively, and $36.3 million and $27.7 million for the nine months ended September 30, 2013 and 2012, respectively, primarily related to Overland Pass Pipeline Company, which are included in cost of sales and fuel in our Consolidated Statements of Income. Accounts payable to our equity method investees at September 30, 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 than previous rates, which reduced ONEOK Partners’ equity earnings from Northern Border Pipeline for the three and nine months ended September 30, 2013, compared with the same periods last year, and are expected to reduce equity earnings and cash distributions from Northern Border Pipeline in the future.

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 coal-bed methane areas in the Powder River Basin.  The reduced coal-bed methane development activities and natural production declines in the dry natural gas formations of the Powder River Basin have resulted in lower dry natural gas volumes available to be gathered.  While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the Powder River Basin on the Bighorn Gas Gathering system, in which ONEOK Partners owns a 49 percent interest, ONEOK Partners tested its investment for impairment at March 31, 2013. The estimated fair value exceeded the carrying value; however, 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. 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 its estimate of fair value are dependent upon events beyond its control. There were no impairment indicators identified in the third quarter 2013. The carrying amount of ONEOK Partners’ investment at September 30, 2013, was $88.7 million, which includes $53.4 million in equity method goodwill.

M. ONEOK PARTNERS

Equity Issuances - In August 2013, ONEOK Partners completed an underwritten public offering of 11.5 million common units at a public offering price of $49.61 per common unit, generating net proceeds of approximately $553.4 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $11.6 million in order to maintain our 2 percent general partner interest in ONEOK Partners. ONEOK Partners used a portion of the proceeds from its August 2013 equity issuance to repay amounts outstanding under its $1.2 billion commercial paper program and the balance was used for general partnership purposes.

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 ONEOK Partners GP’s

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contribution to maintain our 2 percent general partner interest in ONEOK Partners, of approximately $16.3 million. ONEOK Partners used the proceeds for general partnership purposes. ONEOK Partners did not sell any units under this program in the second or third quarter 2013.

As a result of these transactions, our aggregate ownership interest in ONEOK Partners decreased to 41.3 percent at September 30, 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 the issuances, ONEOK Partners GP 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 $84.5 million, net of taxes of $53.0 million, in 2013.

Ownership Interestin ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below at September 30, 2013:

General partner interest	2.0	%
Limited partner interest (a)	39.3	%
Total ownership interest	41.3	%

(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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(Thousands, except per unit amounts)
Distribution per unit	$	0.72	$	0.66	$	2.145	$	1.905
General partner distributions	$	4,512	$	3,979	$	13,399	$	11,019
Incentive distributions	62,634		49,886		184,647		130,968
Distributions to general partner	67,146		53,865		198,046		141,987
Limited partner distributions to ONEOK	66,807		61,240		199,031		171,882
Limited partner distributions to noncontrolling interest	91,676		83,838		272,904		237,109
Total distributions paid	$	225,629	$	198,943	$	669,981	$	550,978

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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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(Thousands, except per unit amounts)
Distribution per unit	$	0.725	$	0.685	$	2.16	$	1.98
General partner distributions	$	4,795	$	4,199	$	13,776	$	11,937
Incentive distributions	67,017		55,162		191,226		149,658
Distributions to general partner	71,812		59,361		205,002		161,595
Limited partner distributions to ONEOK	67,271		63,560		200,422		183,721
Limited partner distributions to noncontrolling interest	100,650		87,014		283,365		251,514
Total distributions declared	$	239,733	$	209,935	$	688,789	$	596,830

Acquisition - On September 30, 2013, ONEOK Partners completed the acquisition of a business comprised of natural gas gathering and processing and natural gas liquids facilities in Converse and Campbell counties, Wyoming, in the NGL-rich Niobrara Shale formation of the Powder River Basin for $305 million, subject to customary purchase price adjustments. The Sage Creek acquisition consists primarily of a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering and natural gas liquids infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. The acquisition is complementary to ONEOK Partners’ existing natural gas liquids assets and provides additional natural gas gathering and processing and natural gas liquids gathering capacity in a region where producers are actively drilling for crude oil and NGL-rich natural gas.

ONEOK Partners accounted for this transaction using the acquisition method of accounting, which requires, among other things, that the assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. ONEOK Partners is developing a preliminary purchase price allocation, which will be adjusted as additional information relative to the fair value of assets and liabilities, which could include intangible assets and goodwill, becomes available. As ONEOK Partners has not completed the purchase price allocation for this transaction, the purchase price has been recorded in property, plant and equipment in our consolidated balance sheet at September 30, 2013.

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 O 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. As a result of the wind down activities discussed in Note B, our Energy Services segment will not execute affiliate transactions with ONEOK Partners after the wind down is completed. ONEOK Partners expects to continue providing midstream services, including marketing natural gas, NGLs and condensate as a service for third parties or other ONEOK affiliates. ONEOK Partners expects to enter into future commodity derivative financial contracts with unaffiliated third parties or ONEOK affiliates.

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

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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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(Thousands of dollars)
Revenues	$	81,324	$	91,096	$	255,298	$	247,851
Expenses
Cost of sales and fuel	$	9,562	$	7,831	$	27,855	$	22,875
Administrative and general expenses	58,549		60,020		192,906		179,017
Total expenses	$	68,111	$	67,851	$	220,761	$	201,892

N. COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical preservation, wildlife preservation and environmental laws and/or regulations that affect many aspects of our present and future operations.  Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction.  These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals.  Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations.  For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows.  In addition, 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.  

In June 2013, the Executive Office of the President of the United States issued the President’s Climate Action Plan, which includes, among other things, plans for further regulatory actions to reduce carbon emissions from various sources. The impact of any such regulatory actions on our facilities and operations is unknown. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, 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 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 have had no material effects on earnings or cash flows during the three and nine months ended September 30, 2013, or in 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

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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 for compliance 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 indicated it would provide additional responses, amendments and/or policy guidance to amend or clarify other portions of the final rule in 2013. The rule was most recently amended in September 2013. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we anticipate a reduction in our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas.  In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to the following:

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

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

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

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

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

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. The CFTC has issued final regulations for most of the provisions of the Dodd-Frank Act, and we have implemented measures to comply with the regulations that are applicable to our businesses. 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. These requirements could affect adversely market liquidity and pricing of derivative contracts, making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

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Legal Proceedings - 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 directed the removal of the cases back to the United States District Court for the District of Nevada for further proceedings. ONEOK, OESC and the other unaffiliated defendants filed a Petition for Writ of Certiorari with the United States Supreme Court on August 26, 2013. The Ninth Circuit has ordered the cases stayed until the final disposition of the Petition for Writ of Certiorari.

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.

O. 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 September 30, 2013, we have a 41.3 percent ownership interest and control ONEOK Partners through our ownership of its general partner. 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 M.  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 and nine months ended September 30, 2013 and 2012, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

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

Three Months Ended September 30, 2013	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	3,053,409	$	219,724	$	298,146		$	646		$	3,571,925
Intersegment revenues	81,324		1		34,050			(115,375		)	—
Total revenues	$	3,134,733	$	219,725	$	332,196		$	(114,729	)	$	3,571,925
Net margin	$	423,574	$	159,233	$	(22,265	)	$	646		$	561,188
Operating costs	122,362		109,304		2,369			2,827			236,862
Depreciation and amortization	61,182		32,347		69			669			94,267
Gain on sale of assets	22		—		—			—			22
Operating income (loss)	$	240,052	$	17,582	$	(24,703	)	$	(2,850	)	$	230,081
Equity earnings from investments	$	27,468	$	—	$	—		$	—		$	27,468
Capital expenditures	$	449,072	$	83,783	$	—		$	4,632		$	537,487

(a) - Our ONEOK Partners segment has regulated and nonregulated operations.  Our ONEOK Partners segment’s regulated operations had revenues of $204.6 million, net margin of $142.3 million and operating income of $76.0 million.

Three Months Ended September 30, 2012	ONEOK Partners (a)			Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,456,364		$	204,930	$	366,955		$	526		$	3,028,775
Intersegment revenues	91,096			2		(3,116		)	(87,982		)	—
Total revenues	$	2,547,460		$	204,932	$	363,839		$	(87,456	)	$	3,028,775
Net margin	$	419,737		$	150,987	$	(17,275	)	$	523		$	553,972
Operating costs	121,176			103,373		4,424			232			229,205
Depreciation and amortization	49,754			31,962		78			(360		)	81,434
Gain on sale of assets	(420		)	—		—			—			(420		)
Operating income (loss)	$	248,387		$	15,652	$	(21,777	)	$	651		$	242,913
Equity earnings from investments	$	28,591		$	—	$	—		$	—		$	28,591
Capital expenditures	$	375,291		$	74,287	$	—		$	8,633		$	458,211

(a) - Our ONEOK Partners segment has regulated and nonregulated operations.  Our ONEOK Partners segment’s regulated operations had revenues of $181.6 million, net margin of $122.9 million and operating income of $63.6 million.

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Nine Months Ended September 30, 2013	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	8,165,061	$	1,167,261	$	1,128,325		$	1,959		$	10,462,606
Intersegment revenues	255,298		5		162,376			(417,679		)	—
Total revenues	$	8,420,359	$	1,167,266	$	1,290,701		$	(415,720	)	$	10,462,606
Net margin	$	1,206,126	$	589,354	$	(159,406	)	$	1,955		$	1,638,029
Operating costs	384,602		330,465		10,930			3,918			729,915
Depreciation and amortization	174,086		100,118		209			1,930			276,343
Gain on sale of assets	342		—		—			—			342
Operating income (loss)	$	647,780	$	158,771	$	(170,545	)	$	(3,893	)	$	632,113
Equity earnings from investments	$	79,744	$	—	$	—		$	—		$	79,744
Investments in unconsolidated affiliates	$	1,201,873	$	—	$	—		$	—		$	1,201,873
Total assets	$	12,863,326	$	3,597,730	$	362,438		$	786,849		$	17,610,343
Noncontrolling interests in consolidated subsidiaries	$	4,588	$	—	$	—		$	2,496,364		$	2,500,952
Capital expenditures	$	1,373,904	$	206,372	$	—		$	17,544		$	1,597,820

(a) - Our ONEOK Partners segment has regulated and nonregulated operations.  Our ONEOK Partners segment’s regulated operations had revenues of $558.9 million, net margin of $390.3 million and operating income of $196.0 million.

Nine Months Ended September 30, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	7,018,503	$	943,034	$	1,009,550		$	1,548		$	8,972,635
Intersegment revenues	247,851		845		84,022			(332,718		)	—
Total revenues	$	7,266,354	$	943,879	$	1,093,572		$	(331,170	)	$	8,972,635
Net margin	$	1,242,289	$	545,823	$	(43,133	)	$	1,542		$	1,746,521
Operating costs	360,410		312,133		13,889			(1,906		)	684,526
Depreciation and amortization	150,024		97,481		284			1,640			249,429
Goodwill impairment	—		—		10,255			—			10,255
Gain on sale of assets	603		—		—			—			603
Operating income (loss)	$	732,458	$	136,209	$	(67,561	)	$	1,808		$	802,914
Equity earnings from investments	$	92,380	$	—	$	—		$	—		$	92,380
Investments in unconsolidated affiliates	$	1,218,282	$	—	$	—		$	—		$	1,218,282
Total assets	$	10,792,593	$	3,258,320	$	450,899		$	862,495		$	15,364,307
Noncontrolling interests in consolidated subsidiaries	$	4,812	$	—	$	—		$	2,105,041		$	2,109,853
Capital expenditures	$	1,011,527	$	205,652	$	—		$	21,729		$	1,238,908

(a) - Our ONEOK Partners segment has regulated and nonregulated operations.  Our ONEOK Partners segment’s regulated operations had revenues of $513.0 million, net margin of $359.7 million and operating income of $182.3 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 and nine months ended September 30, 2013, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Separation of Natural Gas Distribution Segment - On July 25, 2013, we announced that our Board of Directors unanimously authorized management to pursue a plan to separate our natural gas distribution business into a standalone publicly traded company. The natural gas distribution company, named ONE Gas, will consist of ONEOK’s Natural Gas Distribution segment that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.

ONEOK and its subsidiaries will continue to be the sole general partner and own 41.3 percent of ONEOK Partners (NYSE: OKS), one of the largest publicly traded master limited partnerships, and operate our Energy Services segment through the completion of the wind down process.  Under the separation plan, ONEOK shareholders will retain their current shares of ONEOK stock and receive a pro-rata dividend of shares of stock in ONE Gas in a transaction that is expected to be tax-free to ONEOK and its shareholders. The plan provides for the completion of the separation after the receipt of regulatory approvals, and we have begun the process for obtaining these approvals. On October 1, 2013, ONE Gas filed a registration statement on Form 10 with the SEC. Our Board of Directors retains the discretion to determine whether and when to complete the separation.

Market Conditions - Natural gas and natural gas liquids supply continues to increase from drilling activities in crude oil and NGL-rich resource areas. These increased drilling activities have resulted in generally lower NGL prices as well as minimal price volatility and narrower location and seasonal price differentials for natural gas and NGLs in the markets we serve. The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and propane to natural gas, has influenced the volume of ethane natural gas processing plants make available to be gathered in ONEOK Partners’ natural gas liquids business. When economic conditions warrant, certain natural gas processors 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’ natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during the first nine months of 2013, which reduced natural gas liquids volumes gathered and fractionated in ONEOK Partners’ natural gas liquids business and its results of operations.

ONEOK Partners expects ethane rejection to continue through 2015, although at volume levels below those experienced during the first nine months of 2013. ONEOK Partners expects ethane rejection will persist through 2014 at natural gas processing plants, including ONEOK Partners’ own plants, connected to its NGL system in the Mid-Continent and Rocky Mountain regions; and plants located in the Rocky Mountain region, particularly the Williston Basin, will continue to reject ethane through much of 2015. Ethane rejection is expected to have a significant impact on ONEOK Partners’ financial results over this period. However, ONEOK Partners’ natural gas liquids business’ integrated NGL assets enable it to mitigate partially the impact of ethane rejection through minimum volume agreements and its ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials in its optimization activities. In addition, new NGL supply commitments are expected to provide incremental volume in 2014 and 2015 to further mitigate the impact of ethane rejection on ONEOK Partners’ natural gas liquids business. See additional discussion in the “Financial Results and Operating Information” section.

North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from unconventional 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 continue to focus 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.

Wind Down of Energy Services Segment - As a result of challenging industry conditions, in June 2013 we announced an accelerated wind down of our Energy Services segment. Our Energy Services segment no longer fits strategically and has become increasingly smaller on a relative basis because of the market conditions that it has faced and the growth of our other

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businesses. See additional discussion in the “Financial Results and Operating Information” section of our Energy Services segment.

ONEOK Partners’ Sage Creek Acquisition - On September 30, 2013, ONEOK Partners completed the acquisition of a business comprised of natural gas gathering and processing and natural gas liquids facilities in Converse and Campbell counties, Wyoming, in the NGL-rich Niobrara Shale formation of the Powder River Basin for $305 million, subject to customary purchase price adjustments. These assets consist primarily of a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering and natural gas liquids infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. ONEOK Partners plans to invest approximately $135 million, excluding AFUDC, to upgrade and construct natural gas gathering and processing infrastructure and natural gas liquids gathering pipelines. The acquisition is complementary to ONEOK Partners’ existing natural gas liquids assets and provides additional natural gas gathering and processing and natural gas liquids gathering capacity in a region where producers are actively drilling for crude oil and NGL-rich natural gas.

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, the Niobrara Shale formation in the Powder River 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 generally from the petrochemical industry, ONEOK Partners is investing approximately $5.3 billion to $5.6 billion in new capital projects from 2010 through 2016 to meet the needs of natural gas producers and processors in these regions, as well as enhancing its natural gas liquids fractionation, distribution and storage 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 $0.38 per share ($1.52 per share on an annualized basis) in October 2013.  A cash distribution from ONEOK Partners of $0.725 per unit ($2.90 per unit on an annualized basis) was declared in October 2013 for the third quarter of 2013, an increase of 0.5 cents from the previous quarter. The quarterly dividend and distribution payments will be made November 14, 2013, to shareholders and unitholders of record at the close of business on November 4, 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						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2013 vs. 2012					2013 vs. 2012
Financial Results	2013			2012			2013			2012			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	3,571.9		$	3,028.8		$	10,462.6		$	8,972.6		$	543.1		18	%	$	1,490.0		17	%
Cost of sales and fuel	3,010.7			2,474.8			8,824.6			7,226.1			535.9			22	%	1,598.5			22	%
Net margin	561.2			554.0			1,638.0			1,746.5			7.2			1	%	(108.5		)	(6	)%
Operating costs	236.8			229.3			729.9			684.5			7.5			3	%	45.4			7	%
Depreciation and amortization	94.3			81.4			276.3			249.4			12.9			16	%	26.9			11	%
Goodwill impairment	—			—			—			10.3			—			—	%	(10.3		)	100	%
Gain on sale of assets	—			(0.4		)	0.3			0.6			0.4			(100	)%	(0.3		)	(50	)%
Operating income	$	230.1		$	242.9		$	632.1		$	802.9		$	(12.8	)	(5	)%	$	(170.8	)	(21	)%
Equity earnings from investments	$	27.5		$	28.6		$	79.7		$	92.4		$	(1.1	)	(4	)%	$	(12.7	)	(14	)%
Interest expense	$	(81.9	)	$	(71.4	)	$	(244.1	)	$	(218.7	)	$	10.5		15	%	$	25.4		12	%
Net income	$	147.7		$	165.0		$	392.9		$	547.7		$	(17.3	)	(10	)%	$	(154.8	)	(28	)%
Net income attributable to noncontrolling interests	$	85.3		$	99.8		$	217.1		$	298.6		$	(14.5	)	(15	)%	$	(81.5	)	(27	)%
Net income attributable to ONEOK	$	62.4		$	65.2		$	175.8		$	249.1		$	(2.8	)	(4	)%	$	(73.3	)	(29	)%
Capital expenditures	$	537.5		$	458.2		$	1,597.8		$	1,238.9		$	79.3		17	%	$	358.9		29	%

Revenues increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due to higher natural gas and NGL volumes from ONEOK Partners’ recently completed capital projects and new rates in our Natural Gas Distribution segment. These increases were offset partially by significantly narrower NGL price differentials between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, the impact of ethane rejection in ONEOK Partners’ natural gas liquids business and lower net realized natural gas and NGL product prices in ONEOK Partners’ natural gas gathering and processing business.  The increase in natural gas and NGL supply resulting from the development of unconventional resource areas in North America has caused narrower natural gas location and seasonal price differentials in the markets ONEOK Partners serves and generally lower NGL prices and narrower NGL location price differentials during the first nine months of 2013, compared with the same period last year.

Operating income decreased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to noncash charges related to the wind down of our Energy Services segment, significantly narrower NGL location price differentials, lower net realized natural gas and NGL product prices and the impact of ethane rejection in our ONEOK Partners segment. These decreases were offset partially by higher natural gas and NGL volumes from ONEOK Partners’ completed capital projects and new rates in our Natural Gas Distribution segment. The decrease in operating income also reflects an increase in operating costs and depreciation due primarily to the growth of ONEOK Partners’ operations and completed capital projects in its natural gas gathering and processing and natural gas liquids businesses. 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 and nine months ended September 30, 2013, compared with the same periods last year, due primarily to interest costs from ONEOK Partners’ $1.25 billion debt issuance in September 2013 and $1.3 billion debt issuance in September 2012, offset partially by higher 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 and nine months ended September 30, 2013, compared with the same periods last year, due to lower earnings in our ONEOK Partners segment.

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Capital expenditures increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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 41.3 percent ownership interest in ONEOK Partners at September 30, 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 M 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.  Unprocessed natural gas is compressed and gathered through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.  The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are in the form of a mixed, unfractionated NGL stream.

ONEOK Partners gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, 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 formations; and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations. ONEOK Partners also gathers coal-bed methane, or dry natural gas, in the Powder River basin 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 liquids business - ONEOK Partners’ natural gas liquids business owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products primarily in Oklahoma, Kansas, Texas and the Rocky Mountain region 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 on its 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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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.

Growth Projects - Natural gas gathering and processing projects - ONEOK Partners’ natural gas gathering and processing business is investing approximately $2.4 billion to $2.5 billion from 2010 through 2016 in growth projects in the Williston Basin, Cana-Woodford Shale and the Powder River Basin areas that we expect will enable ONEOK Partners to meet the rapidly growing needs of crude oil and 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 McKenzie County, North Dakota, and the Stateline I and Stateline II plants located in 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 Stateline II plants are expected to cost approximately $590 million to $610 million, excluding AFUDC.

ONEOK Partners is investing $150 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota.  The system gathers and transports natural gas from producers in the Bakken Shale and Three Forks formations in the Williston Basin to ONEOK Partners’ Stateline natural gas processing facilities in 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 terms.  The system was placed in service during the second quarter 2013 and cost approximately $130 million, excluding AFUDC. The remaining $20 million investment to expand the system is expected to be completed by the end of 2014 as producers continue their drilling activity.

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 natural gas and natural gas liquids commodity-price sensitivity to increase in the future as the capital projects are completed and volumes increase under its natural gas gathering and processing business’ POP contracts with its customers. ONEOK Partners uses derivative instruments and physical-forward contracts to mitigate its sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for its share of volumes.

Sage Creek acquisition and related projects - On September 30, 2013, ONEOK Partners completed the acquisition of a business comprised of natural gas gathering and processing and natural gas liquids facilities in the NGL-rich Niobrara Shale formation of the Powder River Basin which includes a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. ONEOK Partners plans to invest approximately $50 million, excluding AFUDC, through 2016 to upgrade and construct natural gas gathering and processing infrastructure.

Cana-Woodford Shale projects - ONEOK Partners is investing 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.

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In all of ONEOK Partners’ growth 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 NGLs, particularly propane, is also increasing and is expected to continue in the future.

ONEOK Partners’ natural gas liquids business is investing approximately $2.9 billion to $3.1 billion in NGL-related projects from 2010 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 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.  Beginning in the second half 2012, NGL price differentials narrowed significantly between the Mid-Continent and Gulf Coast market centers. ONEOK Partners expects narrower 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 NGL supply growth in these areas.  The Sterling III Pipeline is designed to transport up to 193 MBbl/d of NGL 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 Sterling II pipelines, which currently 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 $700 million to $800 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 in service November 2013.  The cost of the new fractionator is estimated to be $360 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 is constructing an additional 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.   ONEOK Partners has multi-year supply commitments from producers and natural gas processors for approximately 80 percent of the fractionator’s capacity.

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 was designed to transport 400 MBbl/d from its 80 percent-owned, 160-MBbl/d

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MB-1 fractionator and its wholly owned 75-MBbl/d MB-2 and MB-3 fractionators and its ethane/propane splitter that are currently under construction. The project cost approximately $23 million, excluding AFUDC.

Ethane/Propane Splitter - ONEOK Partners is constructing 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 needs of petrochemical customers, which we expect will grow over the long term. 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 first 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 designed capacity to transport 60 MBbl/d of unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline, was placed in service in April 2013.  The unfractionated NGLs then are delivered to 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 is investing an additional $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135 MBbl/d from the original design capacity of 60 MBbl/d. Project costs for the new pipeline, including the expansion, are estimated to be $590 million to $620 million, excluding AFUDC. The expansion is expected to be completed in the third quarter 2014.

The unfractionated NGLs from the Bakken NGL Pipeline and other supply sources under development in the Rocky Mountain region required 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 were completed in the second quarter 2013 and increased 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 $36 million, excluding AFUDC.

Sage Creek related infrastructure - On September 30, 2013, ONEOK Partners completed the acquisition of a business comprised of natural gas gathering and processing and natural gas liquids facilities in the NGL-rich Niobrara Shale formation of the Powder River Basin which includes a natural gas liquids pipeline.  The acquired natural gas liquids pipeline will be integrated into ONEOK Partners’ natural gas liquids system and used as a platform for future growth opportunities. ONEOK Partners plans to invest approximately $85 million, excluding AFUDC, to build new NGL pipeline infrastructure and connect the Sage Creek natural gas processing plant to its Bakken NGL Pipeline. These projects are expected to be completed by the end of 2014.

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 natural gas liquids 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 added, 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.”

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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						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2013 vs. 2012					2013 vs. 2012
Financial Results	2013			2012			2013			2012			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	3,134.7		$	2,547.5		$	8,420.4		$	7,266.4		$	587.2		23	%	$	1,154.0		16	%
Cost of sales and fuel	2,711.1			2,127.8			7,214.3			6,024.1			583.3			27	%	1,190.2			20	%
Net margin	423.6			419.7			1,206.1			1,242.3			3.9			1	%	(36.2		)	(3	%)
Operating costs	122.3			121.1			384.6			360.4			1.2			1	%	24.2			7	%
Depreciation and amortization	61.2			49.8			174.1			150.0			11.4			23	%	24.1			16	%
Gain on sale of assets	—			(0.4		)	0.4			0.6			0.4			(100	%)	(0.2		)	(33	%)
Operating income	$	240.1		$	248.4		$	647.8		$	732.5		$	(8.3	)	(3	%)	$	(84.7	)	(12	%)
Equity earnings from investments	$	27.5		$	28.6		$	79.7		$	92.4		$	(1.1	)	(4	%)	$	(12.7	)	(14	%)
Interest expense	$	(57.7	)	$	(47.8	)	$	(171.1	)	$	(148.1	)	$	9.9		21	%	$	23.0		16	%
Capital expenditures	$	449.1		$	375.3		$	1,373.9		$	1,011.5		$	73.8		20	%	$	362.4		36	%

Revenues increased for the three and nine months ended September 30, 2013, compared with the same period last year, due to higher natural gas and NGL volumes from ONEOK Partners’ recently completed capital projects, offset partially by significantly narrower NGL price differentials between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, the impact of ethane rejection in ONEOK Partners’ natural gas liquids business and lower net realized natural gas and NGL product prices in ONEOK Partners’ natural gas gathering and processing business.  The increase in natural gas and NGL supply resulting from the development of unconventional resource areas in North America has caused narrower natural gas location and seasonal price differentials in the markets we serve and generally lower NGL prices and narrower NGL location price differentials during the first nine months of 2013, compared with the same period last year.

NGL location price differentials were significantly narrower between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to strong NGL production growth from the development of NGL-rich areas and high ethane inventory levels at Mont Belvieu. An unusually long maintenance outage season in the petrochemical industry during 2013 reduced ethane demand, which contributed to the higher ethane inventory levels.

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 nine months of 2013.

Net margin increased for the three months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• an increase of $35.0 million related to the exchange-services margins, which resulted from higher NGL volumes gathered, 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;

• an increase of $21.1 million due primarily to volume growth in the Williston Basin from ONEOK Partners’ new Stateline I and Stateline II natural gas processing plants and increased well connections resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees in ONEOK Partners’ natural gas gathering and processing business;

• an increase of $9.8 million due to the impact of operational measurement gains of approximately $2.8 million in the third quarter 2013 compared with losses of approximately $7.0 million in the same period last year in ONEOK Partners’ natural gas liquids business; and

• an increase of $4.1 million in storage margins in ONEOK Partners’ natural gas liquids business due primarily to contract renegotiations; offset partially by

• a decrease of $42.3 million in optimization and marketing margins in ONEOK Partners’ natural gas liquids business,

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which resulted from a $39.5 million decrease due primarily to significantly narrower NGL location price differentials, offset partially by higher transportation capacity available for optimization activities due to ethane rejection, and a $17.8 million decrease in marketing margins, offset partially by a $15.0 million increase due primarily to more favorable NGL product price differentials. In the third quarter 2012, ONEOK Partners’ realized higher marketing margins on the sale of NGL inventory held associated with the scheduled maintenance at its Mont Belvieu fractionation facility;

• a decrease of $8.0 million resulting from the impact of ethane rejection in ONEOK Partners’ natural gas liquids business, which resulted in lower NGL volumes;

• a decrease of $6.9 million related to lower isomerization volumes in ONEOK Partners’ natural gas liquids business, resulting from the narrower price differential between normal butane and iso-butane; and

• a decrease of $4.3 million due primarily to lower net realized NGL product prices in ONEOK Partners’ natural gas gathering and processing business.

Net margin decreased for the nine months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• a decrease of $173.8 million in optimization and marketing margins in ONEOK Partners’ natural gas liquids business, due primarily to significantly narrower NGL location price differentials;

• a decrease of $32.0 million resulting from the impact of ethane rejection in ONEOK Partners’ natural gas liquids business, which resulted in lower NGL volumes;

• a decrease of $25.8 million due primarily to lower net realized NGL product prices in ONEOK Partners’ natural gas gathering and processing business;

• a decrease of $15.8 million related to lower isomerization volumes in ONEOK Partners’ natural gas liquids business, resulting from the narrower price differential between normal butane and iso-butane; and

• a decrease of $8.3 million due to changes in ONEOK Partners’ natural gas gathering and processing contract mix and terms associated with ONEOK Partners’ volume growth; offset partially by

• an increase of $124.6 million in exchange-services margins, which resulted from higher NGL volumes gathered, contract renegotiations for higher fees for ONEOK Partners’ NGL exchange-services activities and higher revenues from customers with minimum volume obligations in ONEOK Partners’ natural gas liquids business;

• an increase of $66.0 million due primarily to volume growth in the Williston Basin from ONEOK Partners’ new Stateline I and Stateline II natural gas processing plants and increased well connections resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees in ONEOK Partners’ natural gas gathering and processing business;

• an increase of $19.7 million due to the impact of operational measurement gains in ONEOK Partners’ natural gas liquids business of approximately $11.5 million in 2013 compared with losses of approximately $8.2 million in the same period last year; and

• an increase of $6.4 million due to a contract settlement in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased for the three months ended September 30, 2013, compared with the same period last year, primarily as a result of the growth of ONEOK Partners’ operations and completed capital projects primarily in its natural gas gathering and processing and natural gas liquids businesses, including the following:

• an increase of $3.5 million due to higher materials and supplies, and outside services expenses associated primarily with growth and scheduled maintenance in ONEOK Partners’ operations; partially offset by

• a decrease of $1.7 million in employee-related costs due primarily to lower incentive compensation costs, offset partially by higher labor and employee benefit costs.

Operating costs increased for the nine months ended September 30, 2013, compared with the same period last year, primarily as a result of the growth of ONEOK Partners’ operations and completed capital projects primarily in its natural gas gathering and processing and natural gas liquids businesses, including the following:

• an increase of $10.5 million due to higher materials and supplies, and outside services expenses;

• an increase of $9.0 million in employee-related costs due to higher labor and employee benefit costs, offset partially by lower incentive compensation costs; and

• an increase of $5.1 million due to higher ad valorem taxes.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to the depreciation expense associated with ONEOK Partners’ completed capital projects.

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Equity earnings decreased for the three and nine months ended September 30, 2013, respectively, compared with the same periods last year, due primarily to reduced Northern Border Pipeline transportation rates resulting from a rate settlement with its customers that was approved by the FERC effective January 1, 2013, and lower earnings at Venice Energy Services Company, a natural gas processing facility in which ONEOK Partners own a 10 percent interest. The new long-term transportation rates on Northern Border Pipeline are approximately 11 percent lower, than previous rates, which reduced ONEOK Partners’ equity earnings in 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 2015.

Interest expense increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to interest costs from ONEOK Partners’ $1.25 billion debt issuance in September 2013 and $1.3 billion debt issuance in September 2012, offset partially by higher capitalized interest associated with its investments in growth projects.

Capital expenditures increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses. During the third quarter 2013, ONEOK Partners’ natural gas gathering and processing business connected approximately 340 new wells to its systems compared with approximately 280 in the same period last year. For the nine months ended September 30, 2013, ONEOK Partners’ natural gas gathering and processing business connected approximately 950 wells to its systems compared with approximately 710 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						Nine Months Ended
	September 30,						September 30,
Operating Information	2013			2012			2013			2012
Natural gas gathering and processing business (a)
Natural gas gathered (BBtu/d)	1,389			1,149			1,311			1,091
Natural gas processed (BBtu/d) (b)	1,135			906			1,060			833
NGL sales (MBbl/d)	83			62			77			57
Residue gas sales (BBtu/d)	521			416			475			386
Realized composite NGL net sales price ($/gallon) (c)	$	0.90		$	1.10		$	0.87		$	1.07
Realized condensate net sales price ($/Bbl) (c)	$	90.68		$	86.54		$	87.40		$	87.72
Realized residue gas net sales price ($/MMBtu) (c)	$	3.36		$	3.69		$	3.48		$	3.74
Natural gas liquids business
NGL sales (MBbl/d)	686			615			647			544
NGLs transported-gathering lines (MBbl/d) (a)	574			530			542			517
NGLs fractionated (MBbl/d) (b)	557			581			535			565
NGLs transported-distribution lines (MBbl/d) (a)	454			504			426			489
Conway-to-Mont Belvieu OPIS average price differential - ethane in ethane/propane mix ($/gallon)	$	0.04		$	0.16		$	0.04		$	0.21
Natural gas pipelines business (a)
Natural gas transportation capacity contracted (MDth/d)	5,428			5,249			5,486			5,345
Transportation capacity subscribed	89		%	87		%	90		%	88		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	3.42		$	2.75		$	3.56		$	2.43

(a) - Includes volumes for consolidated entities only.

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

(c) - Presented net of the impact of hedging activities on ONEOK Partners’ equity volumes.

Natural gas volumes gathered and processed and natural gas and NGLs sold in ONEOK Partners’ natural gas gathering and processing business increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due to increased well connections in the Williston Basin and western Oklahoma, completion of additional gathering lines and compression, including ONEOK Partners’ Divide County gathering system, to support ONEOK Partners’ new Stateline I and Stateline II natural gas processing plants placed in service in September 2012 and April 2013, respectively.

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

NGLs transported on gathering lines increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to increased volumes from the Williston Basin made available by ONEOK Partners’ completed Bakken NGL Pipeline and increased volumes in the Mid-Continent and Texas made available through ONEOK Partners’ Cana-Woodford Shale and Granite Wash projects, offset partially by decreases in NGL volumes gathered as a result of ethane rejection.

NGLs fractionated decreased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to decreased volumes as a result of ethane rejection during 2013, offset partially by higher volumes from the Williston Basin made available by ONEOK Partners’ completed Bakken NGL Pipeline.

NGLs transported on distribution lines decreased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to decreased volumes resulting from ethane rejection.

In November 2012, the FERC initiated a review of Viking Gas Transmission’s rates pursuant to Section 5 of the Natural Gas Act. In August 2013, a settlement was reached and filed with the FERC providing for a 2 percent annual reduction in rates beginning January 1, 2014. An Administrative Law Judge certified the settlement in September 2013 and recommended FERC approval. ONEOK Partners expects the FERC to approve the settlement as filed.

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:

	Three Months Ending December 31, 2013
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d)	9,034	$	1.11	/ gallon	61%
Condensate (Bbl/d)	2,213	$	2.41	/ gallon	80%
Total (Bbl/d)	11,247	$	1.37	/ gallon	64%
Natural gas (MMBtu/d)	68,315	$	3.90	/ MMBtu	75%

	Year Ending December 31, 2014
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d)	1,475	$	1.37	/ gallon	11%
Condensate (Bbl/d)	2,233	$	2.24	/ gallon	66%
Total (Bbl/d)	3,708	$	1.89	/ gallon	22%
Natural gas (MMBtu/d)	69,274	$	4.11	/ MMBtu	63%

	Year Ending December 31, 2015
	Volumes Hedged	Average Price			Percentage Hedged
Natural gas (MMBtu/d)	48,877	$	4.19	/ MMBtu	41%

ONEOK Partners expects its natural gas liquids and natural gas commodity-price sensitivity to increase in the future as ONEOK Partners’ capital projects are completed and volumes increase under POP contracts with ONEOK Partners’ customers. ONEOK Partners’ natural gas gathering and processing businesses’ 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 $2.0 million;

• a $1.00 per-barrel change in the price of crude oil would change annual net margin by approximately $1.3 million; and

• a $0.10 per-MMBtu change in the price of natural gas would change annual net margin by approximately $3.7 million.

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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, commodity price fluctuations.  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 E of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on ONEOK Partners’ hedging activities.

Equity Investments - 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 coal-bed methane areas in the Powder River Basin.  The reduced coal-bed methane development activities and natural production declines in the dry natural gas formations of the Powder River Basin have resulted in lower dry natural gas volumes available to be gathered.  While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the Powder River Basin on the Bighorn Gas Gathering system, in which ONEOK Partners owns a 49 percent equity interest, ONEOK Partners tested its investment for impairment at March 31, 2013. The estimated fair value exceeded the carrying value; however, 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. ONEOK Partners was not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in its estimate of fair value are dependent upon events beyond its control. There were no impairment indicators identified in the third quarter 2013. The carrying amount of ONEOK Partners’ investment at September 30, 2013, was $88.7 million, which includes $53.4 million in equity method goodwill.

Natural Gas Distribution

Overview - Our Natural Gas Distribution segment provides natural gas distribution services to more than 2 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				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2013 vs. 2012					2013 vs. 2012
Financial Results	2013		2012		2013		2012		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Gas sales	$	192.2	$	177.3	$	1,071.2	$	853.0	$	14.9		8	%	$	218.2		26	%
Transportation revenues	19.7		19.9		71.8		65.2		(0.2		)	(1	)%	6.6			10	%
Cost of sales	60.5		53.9		577.9		398.1		6.6			12	%	179.8			45	%
Net margin, excluding other revenues	151.4		143.3		565.1		520.1		8.1			6	%	45.0			9	%
Other revenues	7.8		7.7		24.3		25.7		0.1			1	%	(1.4		)	(5	)%
Net margin	159.2		151.0		589.4		545.8		8.2			5	%	43.6			8	%
Operating costs	109.3		103.4		330.5		312.1		5.9			6	%	18.4			6	%
Depreciation and amortization	32.3		31.9		100.1		97.5		0.4			1	%	2.6			3	%
Operating income	$	17.6	$	15.7	$	158.8	$	136.2	$	1.9		12	%	$	22.6		17	%
Capital expenditures	$	83.8	$	74.3	$	206.4	$	205.7	$	9.5		13	%	$	0.7		—	%

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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				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2013 vs. 2012					2013 vs. 2012
	2013		2012		2013		2012		Increase (Decrease)					Increase (Decrease)
Gas sales	(Millions of dollars)
Residential	$	109.1	$	102.3	$	407.5	$	375.3	$	6.8		7	%	$	32.2	9	%
Commercial and industrial	21.8		20.3		82.2		76.7		1.5			7	%	5.5		7	%
Wholesale/public authority	0.8		0.8		3.6		2.9		—			—	%	0.7		24	%
Net margin on gas sales	131.7		123.4		493.3		454.9		8.3			7	%	38.4		8	%
Transportation margin	19.7		19.9		71.8		65.2		(0.2		)	(1	)%	6.6		10	%
Net margin, excluding other revenues	$	151.4	$	143.3	$	565.1	$	520.1	$	8.1		6	%	$	45.0	9	%

Net margin increased for the three months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• an increase of $8.1 million from new rates in all three states; offset partially by

• a decrease of $1.0 million from lower transportation volumes due primarily to lower demand from large customers in Kansas and Oklahoma.

Net margin increased for the nine months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• an increase of $29.8 million from new rates in all three states;

• an increase of $8.0 million due to higher sales volumes due primarily to colder than normal weather in Oklahoma and Kansas in 2013, compared with warmer than normal weather in 2012; and

• an increase of $3.6 million from higher transportation volumes due primarily to higher demand from weather-sensitive customers in Kansas.

Operating costs increased for the three months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• an increase of $2.6 million in employee-related expense, due primarily to higher pension costs resulting from an annual change in the estimated discount rate and higher labor costs, offset partially by lower share-based compensation costs;

• an increase of $1.8 million in ad valorem tax expense primarily as a result of an increase in the level of ad valorem tax expense recovered in base rates, which is offset in net margin. For Kansas Gas Service, actual ad valorem taxes incurred that differ from the level of ad valorem taxes recovered in base rates continue to be deferred and recovered or refunded through the ad valorem tax surcharge;

• an increase of $1.2 million in bad debt expense as a result of increased revenues; and

• an increase of $1.0 million in legal costs.

Operating costs increased for the nine months ended September 30, 2013, compared with the same period last year, due primarily to the following:

• an increase of $12.6 million in employee-related expense, due primarily to higher pension costs resulting from an annual change in the estimated discount rate and higher labor costs;

• an increase of $5.3 million in ad valorem tax expense primarily as a result of an increase in the level of ad valorem tax expense recovered in base rates, which is offset in net margin; and

• an increase of $2.4 million in bad debt expense as a result of increased revenues.

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 increased for the three and nine months ended September 30, 2013, compared with the same periods last year, primarily as a result of extending service to new areas.

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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		Nine Months Ended
	September 30,		September 30,
Number of Customers	2013	2012	2013	2012
Residential	1,929,864	1,918,486	1,945,631	1,932,295
Commercial and industrial	152,808	151,913	155,391	154,430
Wholesale/public authority	2,758	2,765	2,761	2,739
Transportation	12,042	11,934	12,022	11,908
Total customers	2,097,472	2,085,098	2,115,805	2,101,372

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Volumes (MMcf)	2013	2012	2013	2012
Gas sales
Residential	7,545	7,342	79,136	66,060
Commercial and industrial	3,775	3,693	24,806	21,108
Wholesale/public authority	272	555	3,092	5,388
Total volumes sold	11,592	11,590	107,034	92,556
Transportation	43,148	45,792	151,660	149,167
Total volumes delivered	54,740	57,382	258,694	241,723

Residential, commercial and industrial volumes increased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to colder temperatures in 2013; however, the impact on margins was mitigated largely by weather-normalization mechanisms.

Our Energy Services segment was the successful bidder to Oklahoma Natural Gas’ request for proposal for no-notice natural gas storage service resulting in Oklahoma Natural Gas taking the assignment of 18.0 Bcf of storage capacity from an affiliate, effective June 2013. The cost associated with the storage is recoverable through the Oklahoma Natural Gas purchased-gas adjustment clause.

Regulatory Initiatives - Oklahoma - On October 18, 2013, Oklahoma Natural Gas filed a joint application with the OCC to postpone its next rate case, currently required in 2014. The joint stipulation and settlement agreement in support of the application was filed October 25, 2013. If approved, Oklahoma Natural Gas will file a performance-based rate change application in 2014 and a rate case in 2015 based on a test year consisting of the first four quarters of Oklahoma Natural Gas’ operations as a division of ONE Gas.

In March 2013, Oklahoma Natural Gas filed a Performance-Based Rate Change (PBRC) application at the OCC seeking no modification to customers’ base rates. The filing includes a small adjustment to residential, commercial and industrial customers’ monthly charge for energy-efficiency program collections. This filing was approved by the OCC in August 2013.

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 Oklahoma Natural Gas to pursue key energy-efficiency programs and to earn up to $1.5 million annually, if program objectives are achieved. In May 2013, the OCC approved the extension of the program to include the years 2014-2016, as well as adjustments to rebate amounts and targets that were requested by Oklahoma Natural Gas.

Kansas - In October 2012, Kansas Gas Service, the staff of the KCC and the Citizens’ Utility Ratepayer Board filed a joint motion to approve a stipulated settlement agreement granting a $28 million increase in base rates and an $18 million reduction in amounts currently recovered through surcharges, effectively increasing its annual revenues by a net amount of $10 million. The KCC approved this settlement in December 2012, and the new rates were effective January 2013.

In August 2013, Kansas Gas Service filed an application to increase the Gas Systems Reliability Surcharge by $1.5 million. This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases. Staff of the KCC issued its

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report and recommendation that the application be approved as filed. The KCC is expected to make a final ruling by December 2013.

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 May 2013, the City of Austin, Texas, approved the requested increase. In July 2013, the city of El Paso denied Texas Gas Service’s GRIP request, which we appealed to the RRC. In September 2013, the RRC approved Texas Gas Service’s requested increase.

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. Annual rate increases totaling $4.1 million associated with these filings were approved in 2013.

Energy Services

Overview - In June 2013, we announced we will discontinue our Energy Services segment through an accelerated wind down process. Our Energy Services segment continues to face challenging industry conditions that show no signs of improving. Increased natural gas supply and infrastructure, coupled with lower natural gas price volatility have narrowed seasonal and location natural gas price differentials, resulting in limited opportunities to generate revenues to cover our fixed costs on contracted storage and transportation capacity. We executed agreements in 2013 to release a significant portion of our nonaffiliated, third-party natural gas transportation and storage contracts to third parties effective July 1 and September 1, 2013. In addition, pursuant to a request for proposal, our Energy Services segment assigned contracts for 18.0 Bcf of storage capacity leased from an affiliate to our Natural Gas Distribution segment effective June 2013. We expect the Energy Services segment to be classified as discontinued operations, effective March 31, 2014, when substantially all operations of the segment have ceased.

As a result of the accelerated wind down, we recorded noncash charges totaling approximately $113.8 million, before taxes, in the second quarter 2013 and approximately $16.4 million, before taxes, in the third quarter 2013, which were recorded in cost of sales and fuel in our Consolidated Statements of Income. We also expect to record additional noncash charges of approximately $12 million, before taxes, between October 1, 2013, and March 31, 2014, subject to the release or assignment of the remaining natural gas transportation and storage contracts. We expect future cash expenditures associated with the released transportation and storage capacity from the wind down of our Energy Services segment to total approximately $89 million on an after-tax basis with approximately $8 million paid in the fourth quarter 2013, $33 million in 2014, $24 million in 2015 and $24 million over the period 2016 through 2023.

During the wind down process, we will retain 23.5 Bcf of contracted natural gas storage capacity of which 20.5 will expire by March 31, 2014. We expect to release the remaining 3.0 Bcf of natural gas storage capacity effective April 1, 2014. We will utilize this capacity to serve our contracted premium services customers by providing natural gas supply and risk-management services for natural gas and electric utilities and industrial customers. Premium services volumes, revenues and cost of sales decreased materially as we have realigned our business operations with the remaining contracted capacity. Our premium services include next-day and no-notice natural gas delivery services.  Next-day services allow our customers to call on additional natural 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.

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

	Three Months Ended						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2013 vs. 2012					2013 vs. 2012
Financial Results	2013			2012			2013			2012			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	332.2		$	363.8		$	1,290.7		$	1,093.6		$	(31.6	)	(9	)%	$	197.1		18	%
Cost of sales and fuel	354.5			381.1			1,450.1			1,136.7			(26.6		)	(7	)%	313.4			28	%
Net margin	(22.3		)	(17.3		)	(159.4		)	(43.1		)	(5.0		)	29	%	(116.3		)	*
Operating costs	2.3			4.4			10.9			13.9			(2.1		)	(48	)%	(3.0		)	(22	)%
Depreciation and amortization	0.1			0.1			0.2			0.3			—			—	%	(0.1		)	(33	)%
Goodwill impairment	—			—			—			10.3			—			—	%	(10.3		)	(100	)%
Operating loss	$	(24.7	)	$	(21.8	)	$	(170.5	)	$	(67.6	)	$	(2.9	)	13	%	$	(102.9	)	*

* Percentage change is greater than 100 percent.

Segment wind down charges - During the three and nine months ended September 30, 2013, we recorded approximately $16.4 million and $130.2 million, respectively, of noncash charges related to the full release of a significant portion of our natural gas transportation and storage contracts to third parties. During the three months ended September 30, 2013, we made cash payments of $6.2 million related to this obligation.

Operating results - Revenues and cost of sales and fuel have decreased for the three months ended September 30, 2013, compared with the same period last year, due primarily to lower natural gas transportation and storage volumes. Revenues and cost of sales and fuel have significantly increased for the nine months ended September 30, 2013, compared with the same period last year, due primarily to higher natural gas prices. Cost of sales and fuel have also significantly increased due to noncash charges incurred as a result of the full release of a significant portion of our natural gas transportation and storage contracts to third parties related to the accelerated wind down.

Excluding noncash charges related to the released capacity, net margin increased by $11.4 million for the three months ended September 30, 2013, compared with the same period last year, primarily due to reduced contracted transportation and storage capacity resulting in lower demand charges in the current year.

Excluding noncash charges related to the released capacity, net margin increased by $13.9 million for the nine months ended September 30, 2013, compared with the same period last year, primarily due to the following:

• a net increase of $12.9 million in storage and marketing margins, net of hedging activities, due primarily to an increase related to the 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 on natural gas in 2012 and reduced storage capacity resulting in lower demand charges in the current year, offset partially by decreases due to lower realized seasonal storage differentials and marketing margins, net of hedging activities; and

• an increase of $9.5 million in transportation margins, due primarily to reduced contracted transportation capacity resulting in lower demand charges in the current year; offset partially by

• a decrease of $4.5 million in premium-services margins, associated primarily with lower demand fees; and

• a decrease of $3.5 million in financial trading margins.

Operating costs decreased for the three and nine months ended September 30, 2013, compared with the same periods last year, due primarily to lower employee-related expenses.

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 - At September 30, 2013, our natural gas transportation capacity was 0.1 Bcf/d, of which 0.1 Bcf/d was contracted under long-term natural gas transportation contracts, compared with 1.1 Bcf/d of total capacity and 1.0 Bcf/d of long-term capacity at September 30, 2012.  During the third quarter 2013, we released approximately 0.7 Bcf/d of transportation capacity as a result of the accelerated wind down. The remaining 0.1 Bcf/d of transportation capacity will expire by March 31, 2014.

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Our natural gas in storage at September 30, 2013, was 20.2 Bcf, compared with 66.4 Bcf at September 30, 2012.  During the third quarter 2013, our total natural gas storage capacity decreased from 34.1 Bcf at June 30, 2013, to 24.0 Bcf at September 30, 2013, due primarily to 10.1 Bcf of storage capacity we released to third parties. An additional 0.5 Bcf of storage capacity was assigned effective October 1, 2013. The remaining 23.5 Bcf of storage capacity will either be released or will expire by March 31, 2014. At September 30, 2013, our natural gas storage capacity under lease had a maximum withdrawal capability of 0.6 Bcf/d and maximum injection capability of 0.4 Bcf/d.

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 directed the removal of the cases back to the United States District Court for the District of Nevada for further proceedings. ONEOK, OESC and the other unaffiliated defendants filed a Petition for Writ of Certiorari with the United States Supreme Court on August 26, 2013. The Ninth Circuit has ordered the cases stayed until the final disposition of the Petition for Writ of Certiorari.

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

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.

We expect future cash expenditures associated with the released transportation and storage capacity from the wind down of our Energy Services segment to total approximately $89 million on an after-tax basis with approximately $8 million paid in the fourth quarter 2013, $33 million in 2014, $24 million in 2015 and $24 million over the period 2016 through 2023.

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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:

	September 30,	December 31,
	2013	2012
Long-term debt	44%	45%
ONEOK shareholders’ equity	56%	55%
Debt (including notes payable)	50%	54%
ONEOK shareholders’ equity	50%	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:

	September 30,	December 31,
	2013	2012
Long-term debt	62%	61%
Total equity	38%	39%
Debt (including notes payable)	64%	63%
Total equity	36%	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, which expires at the end of 2013.

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, distributions received from its equity-method investments and proceeds from its commercial paper program.  To the extent commercial paper is unavailable, ONEOK’s and ONEOK Partners’ respective revolving credit agreements may be utilized.

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 September 30, 2013, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 48.2 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 to repay our commercial paper notes, if necessary.  Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Credit Agreement.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion.  At September 30, 2013, ONEOK had $515.3 million of commercial paper outstanding, $1.9 million in letters of credit issued under the ONEOK Credit Agreement and approximately $56.5 million of cash and cash equivalents.  ONEOK had approximately $682.8 million of credit

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available at September 30, 2013, under the ONEOK Credit Agreement.  At September 30, 2013, ONEOK could have issued $2.7 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.  As a result of ONEOK Partners’ Sage Creek acquisition on September 30, 2013, its allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to1 for the current quarter and will remain at that level through the first quarter 2014. 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 September 30, 2013, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.2 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 September 30, 2013, ONEOK Partners had $47.0 million in commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners Credit Agreement, approximately $723.0 million of cash and approximately $1.2 billion of credit available under the ONEOK Partners Credit Agreement.  At September 30, 2013, ONEOK Partners could have issued $1.9 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.

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.

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, were approximately $694.3 million.

ONEOK Partners’ Debt Issuances - In September 2013, ONEOK Partners completed an underwritten public offering of $1.25 billion of senior notes, consisting of $425 million, 3.2 percent senior notes due 2018, $425 million, 5.0 percent senior notes due 2023 and $400 million, 6.2 percent senior notes due 2043. A portion of the net proceeds from the offering of approximately $1.24 billion was used to repay amounts outstanding under its commercial paper program, and the balance will be used for general partnership purposes, including but not limited to capital expenditures.

In September 2012, ONEOK Partners completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0 percent senior notes due 2017 and $900 million, 3.375 percent senior notes due 2022.  A portion of the net proceeds from the offering of approximately $1.29 billion was used to repay amounts outstanding under its commercial paper program, and the balance was used for general partnership purposes, including but not limited to capital expenditures.

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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.

ONEOK Partners’ Equity Issuances - In August 2013, ONEOK Partners completed an underwritten public offering of 11.5 million common units at a public offering price of $49.61 per common unit, generating net proceeds of approximately $553.4 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $11.6 million in order to maintain our 2 percent general partner interest in ONEOK Partners. ONEOK Partners used a portion of the proceeds from its August 2013 equity issuance to repay amounts outstanding under its $1.2 billion commercial paper program and the balance was used for general partnership purposes.

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 ONEOK Partners GP’s contribution to maintain our 2 percent general partner interest in ONEOK Partners, of approximately $16.3 million. ONEOK Partners used the proceeds for general partnership purposes. ONEOK Partners did not sell any units under this program in the second or third quarter 2013.

As a result of these transactions, our aggregate ownership interest in ONEOK Partners decreased to 41.3 percent at September 30, 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 the issuances, ONEOK Partners GP contributed approximately $19 million in order to maintain our 2 percent general partner interest in ONEOK Partners.

Interest-rate Swaps - At September 30, 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 $1.6 billion and $1.2 billion for the nine months ending September 30, 2013 and 2012, respectively.  Of these amounts, ONEOK Partners’ capital expenditures were $1.4 billion and $1.0 billion for the nine months ended September 30, 2013 and 2012, respectively.  Capital expenditures increased for the three months ended September 30, 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	$	2,100
Natural Gas Distribution	286
Other	30
Total projected capital expenditures	$	2,416

Credit Ratings - Our credit ratings are shown in the table below:

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

ONEOK’s and ONEOK Partners’ commercial paper programs are each rated currently Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which are investment grade, may be affected by a material change in financial

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ratios or a material event affecting the business.  In July 2013, Moody’s and S&P announced they will review ONEOK’s ratings due to our announcement of the planned separation of our natural gas distribution business.  We expect that the credit rating agencies will assign ONEOK ratings in line with its general partner peers upon completion of the separation of the natural gas distribution business.  ONEOK anticipates receiving slightly lower credit ratings than it has currently following completion of the separation.  In addition, S&P affirmed ONEOK Partners current rating and revised its outlook on ONEOK Partners’ rating to negative due to its expectation that weak commodity prices, particularly NGL prices, could impact ONEOK Partners’ credit profile in 2014.

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.

Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements.  Without investment-grade ratings, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position at September 30, 2013, was $2.5 million.

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 E 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 N of the Notes to Consolidated Financial Statements in our Annual Report. See Note K 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.

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

							Variances
	Nine Months Ended						2013 vs. 2012
	September 30,						Increase (Decrease)
	2013			2012
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,021.5		$	762.9		$	258.6
Investing activities	(1,880.7		)	(1,198.6		)	(682.1		)
Financing activities	1,055.1			1,339.7			(284.6		)
Change in cash and cash equivalents	195.9			904.0			(708.1		)
Change in cash and cash equivalents included in discontinued operations	—			8.8			(8.8		)
Change in cash and cash equivalents from continuing operations	195.9			912.8			(716.9		)
Cash and cash equivalents at beginning of period	583.6			66.0			517.6
Cash and cash equivalents at end of period	$	779.5		$	978.8		$	(199.3	)

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 $902.8 million for the nine months ended September 30, 2013, compared with $1.0 billion 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.”

The changes in operating assets and liabilities increased operating cash flows by approximately $118.7 million for the nine months ended September 30, 2013, compared with a decrease of $259.6 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 - Cash used in investing activities increased for the nine months ended September 30, 2013, compared with the same period in 2012, due primarily to increased capital expenditures related to ONEOK Partners’ growth projects and the Sage Creek acquisition.

Financing Cash Flows - Cash provided by financing activities decreased for the nine months ended September 30, 2013, as compared with the same period in the prior year, primarily due to ONEOK’s January 2012 debt issuance; ONEOK Partners issued a similar amount of debt in both periods. This was offset partially by lower repayment of debt and higher issuance of ONEOK Partners’ common units in 2013. Cash flows were also impacted by increased distributions from ONEOK Partners to noncontrolling interests and increased dividends in 2013, compared with the same period last year.

REGULATORY

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. The CFTC has issued final regulations for most of the provisions of the Dodd-Frank Act, and we have implemented measures to comply with the regulations that are applicable to our businesses. 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. 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.

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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.

On June 25, 2013, the Executive Office of the President of the United States issued the President’s Climate Action Plan, which includes, among other things, plans for further regulatory actions to reduce carbon emissions from various sources. The impact of any such regulatory actions on our facilities and operations is unknown. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, results of operations and cash flows.

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

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.

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.

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Our 2012 total reported emissions were approximately 64.9 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 from the oil and gas industry. 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 “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 RICE NESHAP, initially included a compliance date in 2013.  Subsequent industry appeals and settlements with the EPA have extended timelines for compliance 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 indicated it would provide additional responses, amendments and/or policy guidance to amend or clarify other portions of the final rule in 2013. The rule was most recently amended on September 23, 2013. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we anticipate a reduction in our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS 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 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

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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.

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.

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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;

• 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 or extended periods of ethane rejection;

• 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;

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• 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. 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 E 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

In June 2013, we announced we will discontinue our Energy Services segment through an accelerated wind down process. See Note B of the Notes to Consolidated Financial Statements and the discussion under Energy Services in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on the impact of the wind down activities on the Energy Services operations. As the operations of the Energy Services segment wind down, our exposure to commodity-price risk, seasonal and location-price risk and price volatility has decreased, and we expect it to decrease further upon completion of the wind down.

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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 $12.3 million and $27.4 million of net assets at September 30, 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	40
Fair value of new derivatives entered into during the period	(1,088		)
Other changes in fair value	(3,577		)
Net fair value of derivatives outstanding at September 30, 2013 (a)	$	408

(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: $1.7 million in gains maturing through March 2014 and $1.3 million in losses maturing through March 2016. 

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 D and E 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 $0.1 million and $2.7 million at September 30, 2013 and 2012, respectively.  The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Value-at-Risk	2013		2012		2013		2012
	(Millions of dollars)
Average	$	0.7	$	3.0	$	1.3	$	2.8
High	$	1.6	$	4.0	$	2.7	$	4.0
Low	$	0.1	$	1.8	$	0.1	$	1.8

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 September 30, 2013, compared with September 30, 2012, was due primarily to a decrease in total storage and transportation capacity over the five-year period that VAR is calculated.

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 September 30, 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. Future issuances of long-term debt could be impacted by recent increases in interest rates, which could result in higher interest costs.

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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 third quarter ended September 30, 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 N, “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
July 1-31, 2013	—	$	—	—
August 1-31, 2013	—	$	—	—
September 1-30, 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.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

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ITEM 6. EXHIBITS

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

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

Exhibit No.		Exhibit Description
	4.31	Tenth Supplemental Indenture, dated  September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.200% Senior Notes due 2018 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
	4.32	Eleventh Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 5.000% Senior Notes due 2023 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
	4.33	Twelfth Supplemental Indenture, dated  September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.200% Senior Notes due 2043 (incorporated by reference from Exhibit 4.4 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
	10.63	Underwriting Agreement dated August 7, 2013, among ONEOK Partners, L.P. and Morgan Stanley & Co. LLC, Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on August 12, 2013 (File No. 1-12202)).
	10.64	Underwriting Agreement dated September 9, 2013, among ONEOK Partners, L.P. and ONEOK Partners Intermediate Limited Partnership and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Deutsche Bank Securities Inc., as representatives of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
	31.1	Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification of Derek S. Reiners pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1	Certification of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
	32.2	Certification of Derek S. Reiners pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
	101.INS	XBRL Instance Document
	101.SCH	XBRL Taxonomy Extension Schema Document
	101.CAL	XBRL Taxonomy Calculation Linkbase Document
	101.DEF	XBRL Taxonomy Extension Definitions Document
	101.LAB	XBRL Taxonomy Label Linkbase Document
	101.PRE	XBRL Taxonomy Presentation Linkbase Document

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Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents:  (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2013 and 2012; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012; (iv) Consolidated Balance Sheets at September 30, 2013, and December 31, 2012; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012; (vi) Consolidated Statement of Changes in Equity for the nine months ended September 30, 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: November 6, 2013	By:	/s/ Derek S. Reiners
		Derek S. Reiners
		Senior Vice President,
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

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