ONEOK (OKE) 8-K Other Events

Exhibit 99.2

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and the Notes to Consolidated Financial Statements in Item 8 of this Current Report. The purpose of this reissuance of Item 7 is to reflect as discontinued operations our former natural gas distribution and energy services businesses and the change in our reportable segments. No attempt has been made to modify or update other disclosures presented in our 2013 Form 10-K to reflect events or occurrences after the date of the filing of our 2013 Form 10-K. Therefore, the following discussion and analysis should be read in conjunction with our 2013 Form 10-K and filings we have made with the SEC subsequent to the filing of our 2013 Form 10-K, including our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014, filed on May 7, 2014 and August 6, 2014, respectively.

RECENT DEVELOPMENTS

The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. Due to the separation of our former natural gas distribution business on January 31, 2014, and the wind down of our former energy services business on March 31, 2014, and the subsequent reporting of such businesses as discontinued operations, income from continuing operations reflects the continuing operations of ONEOK Partners and of ONEOK as its general partner. All references to income as used in Management’s Discussion and Analysis of Financial Condition and Results of Operations refer to income from continuing operations. Please refer to the “Financial Results and Operating Information,” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and Notes to Consolidated Financial Statements in this Current Report for additional information.

Separation of Natural Gas Distribution Business - In January 2014, ourboard of directors unanimously approved the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas, Inc. (NYSE: OGS), which was completed on January 31, 2014. ONE Gas consists of ONEOK’s former natural gas distribution business that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service. ONEOK shareholders of record at the close of business on January 21, 2014, retained their current shares of ONEOK stock and received one share of ONE Gas stock for every four shares of ONEOK stock owned in a transaction that was tax-free to ONEOK and its shareholders. In connection with the separation, we received a cash payment of approximately $1.13 billion from ONE Gas and utilized or will utilize the proceeds to repay all of our outstanding commercial paper and to repay approximately $550 million of long-term debt prior to maturity. Our former natural gas distribution business has been classified as discontinued operations for all periods presented.

Wind Down of Energy Services Business -As a result of challenging natural gas market conditions, in June 2013 we announced an accelerated wind down of our energy services business that was completed on March 31, 2014. Our energy services business no longer fit strategically and had become increasingly smaller on a relative basis because of the market conditions that it had faced and the growth of our other businesses. Our former energy services business has been classified as discontinued operations for all periods presented.

Change in Reportable Segments - Following the separation of our natural gas distribution business into ONE Gas and the wind down of our energy services business, our chief operating decision maker reviews the financial performance of each of the three businesses of ONEOK Partners on a regular basis to assess the performance of, and allocate resources to, ONEOK Partners. As a result, our reportable segments have changed to reflect the three business segments of ONEOK Partners. We have reflected the change in reporting segments for all periods presented. See also Note R to the Consolidated Financial Statements included in this Current Report for additional information.

Ownership of ONEOK Partners - ONEOK and its subsidiaries will continue to own all of the general partner interest and certain limited partner interests, which, together, represent a 41.2 percent ownership interest at December 31, 2013, in ONEOK Partners (NYSE: OKS), one of the largest publicly traded master limited partnerships.

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.  We expect continued development of the crude oil and NGL-rich natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin, 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 from the petrochemical industry, ONEOK Partners is investing approximately $6.0 billion to $6.4 billion in new capital projects and acquisitions from 2010 through 2016 including approximately $1.2 billion in new projects and acquisitions announced in 2013, to meet the needs

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of natural gas producers and processors in these regions and expand 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 cash flows and long-term fee-based earnings.

See discussion of ONEOK Partners’ growth projects in the “Financial Results and Operating Information” section in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

ONEOK Partners’ Sage Creek Acquisition -On September 30, 2013, ONEOK Partners completed the acquisition of certain 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. 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. For additional discussion, see Note P of the Notes to Consolidated Financial Statements in this Current Report.

Dividends/Distributions -During 2013, we paid dividends totaling $1.48 per share, an increase of approximately 17 percent over the $1.27 per share paid during 2012.  We declared a quarterly dividend of $0.40 per share ($1.60 per share on an annualized basis) in January 2014, an increase of approximately 6 percent over the $0.36 declared in January 2013.  During 2013, ONEOK Partners paid cash distributions totaling $2.87 per unit, an increase of approximately 11 percent from the $2.59 per unit paid during 2012.  ONEOK Partners paid total cash distributions to us in 2013 of $909.7 million, which includes $639.9 million resulting from our limited-partner interest and $269.9 million related to our general partner interest.  A cash distribution from ONEOK Partners of $0.73 per unit ($2.92 per unit on an annualized basis) was declared in January 2014, an increase of approximately 3 percent from the $0.71 declared in January 2013.

ONEOK Partners Credit Agreement - Effective January 31, 2014, ONEOK Partners amended its Partnership Credit Agreement to increase the size of the facility to $1.7 billion from $1.2 billion and to extend the maturity to January 2019.

ONEOK Credit Agreement - Effective January 31, 2014, we amended the ONEOK Credit Agreement, which reduced the size of our credit facility to $300 million from $1.2 billion and extended the maturity to January 2019.

ONE Gas Credit Agreement - In December 2013, ONE Gas entered into the ONE Gas Credit Agreement, which became effective upon the separation of the natural gas distribution business on January 31, 2014.

ONEOK Partners Debt Issuance - In September 2013, ONEOK Partners completed an underwritten public offering of $1.25 billion of senior notes generating net proceeds of approximately $1.24 billion. The proceeds were used to pay down commercial paper and for general partnership purposes.

ONEOK Partners Equity Issuances - In August 2013, ONEOK Partners completed an underwritten public offering of 11.5 million common units, generating total net proceeds of approximately $553.3 million.  In conjunction with this issuance, we contributed approximately $11.6 million in order to maintain our 2 percent general partner interest. ONEOK Partners used a portion of the proceeds from its August 2013 equity issuance to repay amounts outstanding under its 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 through a sales agent at prices it deems appropriate. 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 year ended December 31, 2013, ONEOK Partners sold approximately 681 thousand common units through this program that resulted in net proceeds, including our contribution to maintain our 2 percent general partner interest in ONEOK Partners, of approximately $36.1 million. ONEOK Partners used the proceeds for general partnership purposes.

As a result of these transactions, our aggregate ownership interest in ONEOK Partners decreased to 41.2 percent at

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December 31, 2013, compared with 43.4 percent at December 31, 2012.

See Note P of the Notes to Consolidated Financial Statements in this Current Report for a discussion of ONEOK Partners’ issuance of common units and distributions to noncontrolling interests.

ONE Gas Debt Issuance - In January 2014, ONE Gas completed a private placement of three series of Senior Notes with an aggregate value of $1.2 billion and received approximately $1.19 billion from the offering, net of issuance costs. ONE Gas paid to ONEOK approximately $1.13 billion in cash from the proceeds of the offering.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

										Variances					Variances
	Years Ended December 31,									2013 vs. 2012					2012 vs. 2011
Financial Results	2013			2012			2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	11,871.9		$	10,184.1		$	11,325.0		$	1,687.8		17	%	$	(1,140.9	)	(10	)%
Cost of sales and fuel	10,222.2			8,540.3			9,745.2			1,681.9			20	%	(1,204.9		)	(12	)%
Net margin	1,649.7			1,643.8			1,579.8			5.9			—	%	64.0			4	%
Operating costs	541.7			491.7			477.2			50.0			10	%	14.5			3	%
Depreciation and amortization	239.3			205.3			179.5			34.0			17	%	25.8			14	%
Gain (loss) on sale of assets	11.9			6.7			(1.0		)	5.2			78	%	7.7			*
Operating income	$	880.6		$	953.5		$	922.1		$	(72.9	)	(8	)%	$	31.4		3	%
Equity earnings from investments	$	110.5		$	123.0		$	127.2		$	(12.5	)	(10	)%	$	(4.2	)	(3	)%
Interest expense	$	(270.6	)	$	(237.6	)	$	(240.0	)	$	33.0		14	%	$	(2.4	)	(1	)%
Income from continuing operations	$	589.1		$	677.7		$	644.9		$	(88.6	)	(13	)%	$	32.8		5	%
Income (loss) and gain on sale of discontinued operations, net of tax	$	(12.1	)	$	65.8		$	114.8		$	77.9		*		$	(49.0	)	(43	)%
Net income attributable to noncontrolling interests	$	310.4		$	382.9		$	399.2		$	(72.5	)	(19	)%	$	(16.3	)	(4	)%
Net income attributable to ONEOK	$	266.5		$	360.6		$	360.6		$	(94.1	)	(26	)%	$	—		—	%
Capital expenditures (a)	$	2,256.6		$	1,866.2		$	1,336.1		$	390.4		21	%	$	530.1		40	%

* Percentage change is greater than 100 percent.

(a) Includes capital expenditures of discontinued operations of $292.1 million, $280.3 million and $242.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

2013 vs. 2012 - Revenues and net margin for 2013, compared with 2012, increased primarily due to higher natural gas and NGL volumes gathered, processed and sold from completed capital projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments, offset partially by lower net realized natural gas and NGL product prices, and ethane rejection. The increase in natural gas supply resulting from the development of nonconventional resource areas in North America has contributed to lower NGL product prices and narrower NGL product price differentials, and narrower natural gas location and seasonal price differentials, compared with 2012, in the markets ONEOK Partners serves. However, in December 2013, the price of propane increased significantly, and the differential between the Conway, Kansas, and Mont Belvieu, Texas, markets for propane also widened in favor of Conway, Kansas, due to colder than normal weather and lower propane inventory levels. These higher propane prices and wider location differentials are expected to continue throughout the end of the 2014 winter heating season, which we expect will have a favorable impact on the Natural Gas Liquids segment’s first quarter 2014 financial results.

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 2013, compared with 2012, due primarily to strong NGL production growth from the development of NGL-rich areas, exceeding the petrochemical industry’s capacity to consume the increased supply resulting in higher ethane inventory levels at Mont Belvieu. Additionally, an unusually long maintenance outage season in the petrochemical industry during 2013 reduced ethane demand, which also contributed to the higher ethane inventory levels.

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The differential between the composite price of NGL products and the price of natural gas, particularly the differential between ethane and natural gas, has influenced the volume of NGLs recovered from natural gas processing plants. The low ethane prices have resulted in ethane rejection at most of ONEOK Partners’ natural gas processing plants and some of its customers’ natural gas processing plants connected to its natural gas liquids system in the Mid-Continent and Rocky Mountain regions during 2013. We expect that natural gas liquids volumes will be affected negatively in the Natural Gas Liquids segment as a result of ethane rejection. We expect ethane rejection will persist through much of 2016, after which new world-scale ethylene production capacity is expected to begin coming on line, although market conditions may result in periods where it is economical to recover the ethane component in the natural gas stream. Ethane rejection is expected to have a significant impact on our financial results during this period. However, the Natural Gas Liquids segment’s integrated assets enable it to mitigate partially the impact of ethane rejection through minimum volume commitments 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 increase volumes in 2014 through 2016 to mitigate further the impact of ethane rejection on the Natural Gas Liquids segment.

Operating costs and depreciation and amortization increased for 2013, compared with 2012, due primarily to the growth of ONEOK Partners’ operations related to the completed capital projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Interest expense increased in 2013, compared with 2012, primarily as a result of higher interest costs incurred associated with a full year of interest costs on ONEOK Partners’ issuance of $1.3 billion of senior notes in September 2012 and interest costs on ONEOK Partners’ issuance of $1.25 billion of senior notes in September 2013. This was offset partially by higher capitalized interest associated with the investments in ONEOK Partners’ growth projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Net income attributable to noncontrolling interests reflects primarily the earnings of ONEOK Partners attributable to the portion of ONEOK Partners that we do not own.

Income from discontinued operations for 2013, compared with 2012, decreased due primarily to $138.6 million in noncash charges related to the accelerated wind down of our former energy services business from the release of a significant portion of its natural gas transportation and storage contracts to third parties. Net income from discontinued operations for 2013 also reflects approximately $9.4 million in costs incurred related to the separation of the natural gas distribution business.

Capital expenditures increased for 2013, compared with 2012, due primarily to the growth projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

2012 vs. 2011 - Revenues for 2012, compared with 2011, decreased due to lower net realized natural gas and NGL product prices, offset partially by higher natural gas and NGL sales volumes from ONEOK Partners’ completed capital projects. The increase in natural gas supply resulting from the development of nonconventional resource areas in North America and a warmer than normal winter in 2012 caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets ONEOK Partners served.  NGL prices, particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production growth from the development of NGL-rich areas. Propane prices also were affected by a warmer than normal winter. During the second half of 2012, NGL location price differentials also narrowed due to strong production growth, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers.

The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and natural gas, may influence the volume of NGLs recovered from natural gas processing plants.  When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants.  Price differentials between ethane and natural gas resulted in periods of ethane rejection in the Mid-Continent and Rocky Mountain regions during 2012. Ethane rejection did not have a material impact on ONEOK Partners’ financial results in 2012.

Operating income for 2012, compared with 2011, increased due to higher volumes from completed capital projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments. The increase was offset partially by less favorable NGL product price differentials and lower NGL transportation capacity available for optimization activities in the Natural Gas Liquids segment. Additionally, the increase was offset by higher compression and processing costs and lower realized natural gas and NGL product prices, particularly ethane and propane, in the Natural Gas Gathering and Processing segment.

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Operating costs and depreciation and amortization increased for 2012, compared with 2011, due primarily to the growth of ONEOK Partners’ operations related to its completed capital projects.

Interest expense decreased in 2012, compared with 2011, primarily as a result of higher capitalized interest associated with ONEOK Partners’ growth projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments, offset partially by higher interest costs from ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012.

Net income attributable to noncontrolling interests reflects primarily the earnings of ONEOK Partners attributable to the portion of ONEOK Partners that we do not own.

Income from discontinued operations for 2012, compared with 2011, decreased due to lower margins in our former energy services business due primarily to the impact of lower realized natural gas prices due to narrower natural gas seasonal and location price differentials and the impact of our hedging strategies on our storage and marketing and transportation margins and a nonrecurring goodwill impairment charge in the first quarter 2012.

Capital expenditures increased in 2012, compared with 2011, due to the growth projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

More information regarding our results of operations is provided in the following discussion of operating results for each of our segments.

Natural Gas Gathering and Processing

Growth Projects - The Natural Gas Gathering and Processing segment is investing approximately $3.0 billion to $3.3 billion from 2010 through 2016 in growth projects, including approximately $950 million in new projects and acquisitions announced in 2013, in NGL-rich areas in the Williston Basin, Cana-Woodford Shale and the Powder River Basin areas that we expect will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - 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 also plans to construct a 200 MMcf/d processing facility, the Lonesome Creek plant, located in McKenzie County, North Dakota. ONEOK Partners has current acreage dedications of approximately 3.1 million acres supporting these plants.  In addition, it 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. Construction costs, excluding AFUDC, for the Garden Creek II plant and related infrastructure are expected to be approximately $310 million to $345 million, and for the Garden Creek III plant and related infrastructure will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be completed during the third quarter 2014 and the first quarter 2015, respectively. The Stateline I natural gas processing facility was placed into service in September 2012, and the Stateline II natural gas processing facility was placed into service in April 2013. Together with the related infrastructure, the Stateline I and Stateline II plants cost approximately $565 million, excluding AFUDC. Construction costs, excluding AFUDC, for the Lonesome Creek natural gas gathering plant and related infrastructure are expected to be approximately $550 million to $680 million. The Lonesome Creek plant is expected to be completed in the fourth quarter 2015.

ONEOK Partners is investing approximately $150 million, excluding AFUDC, 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. Portions of the system were placed in service during the second quarter 2013, and the remaining system expansion is expected to be completed by the end of 2014.

Sage Creek acquisition and related projects - On September 30, 2013, ONEOK Partners completed the acquisition of certain natural gas gathering and processing and natural gas liquids facilities in the NGL-rich Niobrara Shale area 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

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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 be completed in March 2014.  The related additional infrastructure is expected to increase capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.

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.  The routine growth capital needed to connect to new wells and expand ONEOK Partners’ infrastructure is expected to increase compared with its historical levels of routine growth capital.

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

Selected Financial Results - The Natural Gas Gathering and Processing segment’s 2013 operating results include the benefits from its completed growth projects. Operating results for 2013 reflect the completion of the Stateline II natural gas processing plant, which was placed in service in April 2013; and the Stateline I natural gas processing plant, which was placed in service in September 2012. Placing these plants and their related infrastructure in service has resulted in increases in natural gas volumes gathered and processed in the Williston Basin.  We expect drilling activities and development of the reserves to continue in the Williston Basin and Niobrara Shale in the Rocky Mountain region and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas. The following table sets forth certain selected financial results for the Natural Gas Gathering and Processing segment for the periods indicated:

								Variances					Variances
	Years Ended December 31,							2013 vs. 2012					2012 vs. 2011
Financial Results	2013		2012		2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	1,208.7	$	934.2	$	917.5		$	274.5		29	%	$	16.7		2	%
Residue gas sales	620.5		403.8		461.5			216.7			54	%	(57.7		)	(13	)%
Gathering, compression, dehydration and processing fees and other revenue	222.3		177.7		154.5			44.6			25	%	23.2			15	%
Cost of sales and fuel	1,550.9		1,060.5		1,130.6			490.4			46	%	(70.1		)	(6	)%
Net margin	500.6		455.2		402.9			45.4			10	%	52.3			13	%
Operating costs	193.3		164.0		153.7			29.3			18	%	10.3			7	%
Depreciation and amortization	103.9		83.0		68.3			20.9			25	%	14.7			22	%
Gain (loss) on sale of assets	0.4		2.2		(0.3		)	(1.8		)	(82	)%	2.5			*
Operating income	$	203.8	$	210.4	$	180.6		$	(6.6	)	(3	)%	$	29.8		17	%
Equity earnings from investments	$	23.5	$	29.1	$	30.5		$	(5.6	)	(19	)%	$	(1.4	)	(5	)%
Capital expenditures	$	774.4	$	566.1	$	623.7		$	208.3		37	%	$	(57.6	)	(9	)%
Cash paid for acquisitions	$	241.9	$	—	$	—		$	241.9		*		$	—		—	%

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Net margin increased primarily as a result of the following:

• an increase of $100.1 million due primarily to volume growth in the Williston Basin from ONEOK Partners’ 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, higher NGL volumes sold and higher fees; and

• an increase of $6.4 million due to a contract settlement in 2013; offset partially by

• a decrease of $41.7 million due primarily to lower net realized NGL prices;

• a decrease of $13.4 million due primarily to changes in contract mix and terms associated with ONEOK Partners’ volume growth; and

• a decrease of $3.5 million due to lower dry natural gas volumes gathered as a result of continued declines in coal-bed

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methane production in the Powder River Basin.

Operating costs increased due primarily to the growth of ONEOK Partners’ operations and reflect the following:

• an increase of $16.8 million in higher materials and supplies, and outside service expenses;

• an increase of $10.3 million in employee-related costs due to higher labor and employee benefit costs, offset partially by lower incentive compensation costs; and

• an increase of $2.2 million due to higher ad valorem taxes.

Depreciation and amortization increased due to the completion of the Stateline I and Stateline II natural gas processing plants in the Williston Basin, the completion of well connections and infrastructure projects supporting ONEOK Partners’ volume growth in the Williston Basin and its acquisition of the Sage Creek plant in Wyoming.

Equity earnings from investments decreased due primarily to lower NGL prices and declines in volumes gathered by certain of ONEOK Partners’ equity investments in the Powder River Basin.

Capital expenditures increased due to the growth projects discussed above. ONEOK Partners connected approximately 1,160 wells to its systems in 2013, compared with approximately 940 in 2012. In 2013, ONEOK Partners also completed the Sage Creek acquisition in the NGL-rich Niobrara shale area of the Powder River Basin and acquired the remaining 30 percent interest in its Maysville natural gas processing facility.

We expect capital expenditures to increase in 2014 as construction continues on ONEOK Partners’ growth projects.  See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of projected capital expenditures.

2012 vs. 2011 - Net margin increased primarily as a result of the following:

• an increase of $131.5 million due to volume growth in the Williston Basin from ONEOK Partners’ new Garden Creek and Stateline I natural gas processing plants and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees; offset partially by

• a decrease of $38.1 million due primarily to higher compression costs and less favorable contract terms associated with ONEOK Partners’ volume growth in the Williston Basin;

• a decrease of $31.4 million due to lower net realized natural gas and NGL prices, particularly ethane and propane; and

• a decrease of $5.9 million due to lower dry natural gas volumes gathered in the Powder River Basin as a result of continued declines in coal-bed methane production.

Operating costs increased due primarily to the growth of ONEOK Partners’ operations and reflect the following:

• an increase of $4.9 million in higher materials and supplies and outside service expenses;

• an increase of $2.1 million due to higher ad valorem taxes; and

• an increase of $1.5 million related to higher labor and employee-related costs.

Depreciation and amortization increased due to the completion of the Garden Creek and Stateline I natural gas processing plants in the Williston Basin and the completion of well connections and infrastructure projects supporting the volume growth in the Williston Basin.

Capital expenditures decreased due primarily to the timing of expenditures on ONEOK Partners’ growth projects discussed above, offset partially by the completion of approximately 940 well connections in the Williston Basin and Mid-Continent areas in 2012, compared with approximately 600 well connections in 2011.

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

	Years Ended December 31,
Operating Information (a)	2013		2012		2011
Natural gas gathered (BBtu/d)	1,347		1,119		1,030
Natural gas processed (BBtu/d) (b)	1,094		866		713
NGL sales (MBbl/d)	79		61		48
Residue gas sales (BBtu/d)	497		397		317
Realized composite NGL net sales price ($/gallon) (c)	$	0.87	$	1.06	$	1.08
Realized condensate net sales price ($/Bbl) (c)	$	86.00	$	88.22	$	82.56
Realized residue gas net sales price ($/MMBtu) (c)	$	3.53	$	3.87	$	5.47

(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 gathered, natural gas processed, NGLs sold and residue gas sold increased for each of the comparable periods due to increased well connections and completion of growth projects, offset partially by continued declines in dry natural gas from coal-bed methane production in the Powder River Basin in Wyoming and reduced drilling activity and natural production declines in Kansas.

ONEOK Partners’ Garden Creek, Stateline I and Stateline II natural gas processing plants have the capability to recover ethane when economic conditions warrant but did not do so during 2013. As a result, the equity NGL volumes are weighted more toward propane, iso-butane, normal butane and natural gasoline and are expected to remain so until ethane recovery resumes.

	Years Ended December 31,
Operating Information (a) (d)	2013			2012			2011
Commodity
NGL sales (Bbl/d) (b)	14,390			11,575			9,290
Residue gas sales (MMBtu/d) (c)	71,710			48,782			30,134
Condensate sales (Bbl/d) (b)	2,365			2,287			2,030
Percentage of total net margin	66		%	69		%	68		%
Fee-based
Wellhead volumes (MMBtu/d)	1,346,852			1,118,693			1,030,045
Average rate ($/MMBtu)	$	0.34		$	0.35		$	0.34
Percentage of total net margin	34		%	31		%	32		%

(a) - Includes volumes for consolidated entities only.

(b) - Represents equity volumes.

(c) - Represent equity volumes net of fuel.

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

Commodity-Price Risk - The Natural Gas Gathering and Processing segment is exposed to commodity-price risk as a result of receiving commodities in exchange for its services.  A small percentage of its services, based on volume, are provided through keep-whole contracts.  See discussion regarding ONEOK Partners’ commodity-price risk under “Commodity-Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk in our Annual Report.

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 their 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 of the Powder River Basin.  The reduced coal-bed methane development activities and production declines in the dry natural gas formations of the Powder River Basin have resulted in lower 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.  A continued decline in volumes gathered in this area may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and could result in noncash charges to earnings.

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Due to recent reductions in producer activity and declines in natural gas volumes gathered in the dry natural gas area of 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 December 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. The carrying amount of its investment at December 31, 2013, was $87.8 million, which includes $53.4 million in equity method goodwill.

Natural Gas Liquids

Growth Projects - ONEOK Partners’ growth strategy in the Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region into Texas.  Increasing crude oil, natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required additional capital investments to expand 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 in the next two to four years, and international demand for NGLs, particularly propane, is expected to increase into the future.

The Natural Gas Liquids segment is investing approximately $3.0 billion to $3.1 billion in NGL-related projects from 2010 through 2016, including approximately $250 million in new projects and acquisitions announced in 2013.  These investments will accommodate the transportation and fractionation of growing NGL supply 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.  

During 2013, NGL location price differentials remained narrow between the Mid-Continent and Gulf Coast market centers. We expect these narrower NGL price differentials to continue as new fractionators and pipelines, including its growth projects discussed below, continue to alleviate constraints between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers. In addition, new natural gas liquids pipeline projects are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica basins to the Mont Belvieu, Texas, market center that may affect NGL prices, as well as compete with or displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where ONEOK Partners’ assets are located.

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 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 in March 2014.

The project also includes reconfiguration of ONEOK Partners’ 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 $750 million to $800 million, excluding AFUDC.

MB-2 Fractionator - In December 2013, ONEOK Partners placed in service a 75 MBbl/d fractionator, MB-2, near its storage facility in Mont Belvieu, Texas. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity. The project cost approximately $375 million, excluding AFUDC.

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

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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 up to 400 MBbl/d from ONEOK Partners’ 80 percent-owned, 160 MBbl/d 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 is expected to 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 in March 2014.  The ethane/propane splitter is expected to cost approximately $46 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 region.  NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from ONEOK Partners’ natural gas processing plants. The pipeline cost approximately $455 million, excluding AFUDC.

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 designed capacity of 60 MBbl/d. The expansion is expected to be completed in the third quarter 2014. ONEOK Partners also plans to invest approximately $100 million to complete a second expansion of the Bakken NGL Pipeline to increase its capacity to 160 MBbl/d. This expansion is expected to be completed in the second quarter 2016.

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’ share of the costs for this project was approximately $36 million, excluding AFUDC.

Sage Creek related infrastructure - On September 30, 2013, ONEOK Partners completed the acquisition of certain 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 natural gas liquids pipeline infrastructure and connect the Sage Creek natural gas processing plant to its Bakken NGL Pipeline. These projects are expected to be completed in the fourth quarter 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.

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 its 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

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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 its Arbuckle Pipeline to increase its capacity to 240 MBbl/d.  These projects have added, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to its 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 capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources.”

Selected Financial Results and Operating Information The Natural Gas Liquids segment’s 2013 operating results reflect the benefits from the following completed growth projects:

• the Bakken NGL Pipeline, which was placed in service in April 2013;

• the Divide County, North Dakota, natural gas processing system, portions of which were placed in service in the second quarter 2013;

• the expansion of the Overland Pass Pipeline, which was placed in service in the second quarter 2013;

• the Ethane Header Pipeline, which was placed in service in April 2013;

• the expansion of the Bushton fractionator, which was placed in service in September 2012; and

• the expansion of the Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas, which was placed in service in April 2012.

These projects have resulted in additional natural gas liquids volumes gathered, fractionated and transported across ONEOK Partners’ natural gas liquids systems; however, the volumes fractionated and transported decreased in 2013 due to ethane rejection.  We expect these investments along with its other announced growth projects will accommodate the growing NGL supply from shale and other resource development areas across its asset base and will continue to alleviate infrastructure constraints between the Mid-Continent and Texas Gulf coast regions to meet the increasing petrochemical industry and NGL export demand.

The following tables set forth certain selected financial results and operating information for the Natural Gas Liquids segment for the periods indicated:

									Variances					Variances
	Years Ended December 31,								2013 vs. 2012					2012 vs. 2011
Financial Results	2013		2012			2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	9,857.7	$	8,479.7		$	9,764.2		$	1,378.0		16	%	$	(1,284.5	)	(13	)%
Exchange service and storage revenues	839.3		707.6			531.6			131.7			19	%	176.0			33	%
Transportation revenues	81.0		69.3			65.5			11.7			17	%	3.8			6	%
Cost of sales and fuel	9,908.1		8,349.3			9,469.5			1,558.8			19	%	(1,120.2		)	(12	)%
Net margin	869.9		907.3			891.8			(37.4		)	(4	)%	15.5			2	%
Operating costs	236.6		223.8			198.9			12.8			6	%	24.9			13	%
Depreciation and amortization	89.2		74.3			63.9			14.9			20	%	10.4			16	%
Gain (loss) on sale of assets	0.8		(1.0		)	(0.4		)	1.8			*		(0.6		)	*
Operating income	$	544.9	$	608.2		$	628.6		$	(63.3	)	(10	)%	$	(20.4	)	(3	)%
Equity earnings from investments	$	22.0	$	20.7		$	19.9		$	1.3		6	%	$	0.8		4	%
Allowance for equity funds used during construction	$	30.4	$	13.5		$	2.1		$	16.9		*		$	11.4		*
Capital expenditures	$	1,128.3	$	968.5		$	401.3		$	159.8		16	%	$	567.2		*
Cash paid for acquisitions	$	153.0	$	—		$	—		$	153.0		*		$	—		—	%

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Net margin decreased primarily as a result of the following:

• a decrease of $162.7 million in optimization and marketing margins, which resulted from a $202.5 million decrease due primarily to significantly narrower NGL location price differentials. This decrease was offset partially by an increase of $35.7 million due primarily to more favorable NGL product price differentials;

• a decrease of $48.8 million resulting from the impact of ethane rejection, which resulted in lower NGL volumes; and

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• a decrease of $22.4 million related to lower isomerization volumes, resulting from the narrower price differential between normal butane and iso-butane; offset partially by

• an increase of $166.5 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;

• an increase of $19.5 million due to the impact of operational measurement gains of approximately $9.7 million in 2013 compared with losses of approximately $9.8 million in 2012; and

• an increase of $10.5 million in storage margins due primarily to contract renegotiations.

Operating costs increased primarily as a result of the growth of ONEOK Partners’ natural gas liquids operations and reflect the following:

• an increase of $5.4 million due to higher ad valorem taxes related to its completed capital projects; and

• an increase of $5.0 million in employee-related costs due to higher labor and employee benefit costs due to the growth of its operations related to its completed capital projects, offset partially by lower incentive compensation costs.

Depreciation and amortization expense increased due primarily to the depreciation associated with ONEOK Partners’ completed natural gas liquids capital projects.

Equity earnings increased compared with 2012, due primarily to higher volumes delivered to Overland Pass Pipeline from ONEOK Partners’ Bakken NGL Pipeline that was placed in service in April 2013, offset partially by reduced volumes as a result of ethane rejection. The impact of ethane rejection reduced equity earnings by $13.3 million compared with 2012.

Capital expenditures and the allowance for equity funds used during construction increased due primarily to ONEOK Partners’ growth projects discussed above. In 2013, it also completed the Sage Creek acquisition in the NGL-rich Niobrara shale area of the Powder River Basin that included natural gas liquids gathering pipelines.

2012 vs. 2011 - NGL prices, particularly ethane and propane, decreased in 2012 due primarily to increased NGL production from the development of NGL-rich areas and lower crude-oil prices. During the second half of 2012, due to strong NGL production growth from the development of NGL-rich areas, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers, NGL location price differentials narrowed between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas.

Net margin increased primarily as a result of the following:

• an increase of $101.5 million related to higher NGL volumes gathered and fractionated across ONEOK Partners’ natural gas liquids systems related to completion of certain growth projects, and contract renegotiations for higher fees associated with its NGL exchange services activities; and

• an increase of $13.1 million due to higher natural gas liquids storage margins as a result of contract renegotiations that resulted in higher fees; offset partially by

• a decrease of $91.2 million in optimization and marketing margins from a $94.6 million decrease due to narrower NGL price differentials and reduced transportation capacity available for optimization activities, as an increasing portion of its transportation capacity between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers was utilized by its exchange services activities to produce fee-based earnings. This decrease was offset partially by a $3.5 million increase in its marketing activities that benefited from higher truck and rail volumes;

• a decrease of $4.5 million due to the impact of higher operational measurement losses; and

• a decrease of $3.4 million related to lower isomerization margins resulting from lower isomerization volumes.

Operating costs increased primarily as a result of the growth of ONEOK Partners’ natural gas liquids operations and reflect the following:

• an increase of $16.1 million due to higher material and outside services expenses, including costs associated with scheduled maintenance at its existing facilities;

• an increase of $3.8 million due to higher labor and employee-related costs; and

• an increase of $1.8 million due to higher ad valorem taxes.

Depreciation and amortization expense increased due primarily to the depreciation associated with its completed capital projects.

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Capital expenditures and the allowance for equity funds used during construction increased due primarily to the growth projects discussed above.

Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which ONEOK Partners contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant. On June 30, 2011, through a series of transactions, we sold OBPI to ONEOK Partners and OBPI closed the purchase option and terminated the equipment leases.  The total amount paid by ONEOK Partners to complete the transactions was approximately $94.2 million, which included the reimbursement to us of obligations related to the Processing and Services Agreement.

	Years Ended December 31,
Operating Information	2013		2012		2011
NGL sales (MBbl/d)	657		572		497
NGLs fractionated (MBbl/d) (a)	535		574		537
NGLs transported - gathering lines (MBbl/d) (b)	547		520		436
NGLs transported - distribution lines (MBbl/d) (b)	435		491		473
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.04	$	0.17	$	0.28

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

(b) Includes volumes for consolidated entities only.

2013 vs. 2012 - NGLs transported on gathering lines increased 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 region and Texas made available through its Cana-Woodford Shale and Granite Wash projects, offset partially by decreases in NGL volumes gathered as a result of ethane rejection.

NGLs fractionated decreased due primarily to decreased volumes as a result of ethane rejection during 2013, offset partially by higher volumes supplied from the Williston Basin made available by ONEOK Partners’ completed Bakken NGL Pipeline.

NGLs transported on distribution lines decreased due primarily to decreased volumes as a result of ethane rejection.

2012 vs. 2011 - NGLs gathered and fractionated increased due primarily to increased throughput from existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions.  The increased gathering capacity in the Mid-Continent region and Texas was made available through ONEOK Partners’ Cana-Woodford Shale and Granite Wash projects, which were placed in service in April 2012. The increased Gulf Coast fractionation capacity was made available by ONEOK Partners’ 60 Mbl/d fractionation services agreement with Targa Resources Partners that began in the second quarter 2011.

NGLs transported on distribution lines increased due primarily to the Sterling I pipeline expansion and higher volumes transported on ONEOK Partners’ distribution pipelines between its Mid-Continent facilities to optimize the delivery of supply.

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Natural Gas Pipelines

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

								Variances					Variances
	Years Ended December 31,							2013 vs. 2012					2012 vs. 2011
Financial Results	2013		2012		2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	233.0	$	220.9	$	233.6		$	12.1		5	%	$	(12.7	)		(5	)%
Storage revenues	70.4		68.7		68.8			1.7			2	%	(0.1		)		—	%
Gas sales and other revenues	22.1		30.8		35.4			(8.7		)	(28	)%	(4.6		)		(13	)%
Cost of sales	39.8		34.3		53.4			5.5			16	%	(19.1		)		(36	)%
Net margin	285.7		286.1		284.4			(0.4		)	—	%	1.7				1	%
Operating costs	101.2		101.9		108.6			(0.7		)	(1	)%	(6.7		)		(6	)%
Depreciation and amortization	43.5		45.7		45.4			(2.2		)	(5	)%	0.3				1	%
Gain (loss) on sale of assets	10.6		5.3		(0.3		)	5.3			*		5.6				*
Operating income	$	151.6	$	143.8	$	130.1		$	7.8		5	%	$	13.7		��	11	%
Equity earnings from investments	$	65.0	$	73.2	$	76.9		$	(8.2	)	(11	)%	$	(3.7	)		(5	)%
Capital expenditures	$	34.7	$	25.4	$	37.8		$	9.3		37	%	$	(12.4	)		(33	)%

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Operating income increased in 2013, compared with 2012, reflecting an increase in transportation margins of $9.6 million due primarily to higher rates on Guardian Pipeline and higher contracted capacity with natural gas producers on ONEOK Partners’ intrastate pipelines, offset partially by a decrease of $3.9 million from lower net retained fuel. Additionally, operating costs included an increase of $2.4 million due to higher employee-benefit costs. Gain on sale of assets increased in 2013 from 2012 primarily due to a $10.5 million gain on sale of excess noncurrent natural gas in storage in 2013 as a result of storage optimization review that resulted in additional working gas capacity of 2.0 Bcf; 2012 results reflected a gain on sale of a natural gas pipeline lateral of $5.7 million.

Equity earnings from investments decreased in 2013, compared with 2012, due to reduced transportation rates resulting from a Northern Border Pipeline rate settlement, effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower than previous rates, which reduced equity earnings and cash distributions compared with 2012. Substantially all of Northern Border Pipeline’s long-haul transportation capacity has been contracted through June 2015.

2012 vs. 2011 - Net margin remained relatively unchanged as a result of the following:

• an increase of $3.3 million due to higher contracted capacity in western Oklahoma and the Texas panhandle on ONEOK Partners’ intrastate pipelines to transport increasing natural gas supply to market, offset partially by lower negotiated rates on Midwestern Gas Transmission; offset by

• a decrease of $1.0 million due primarily to lower prices on ONEOK Partners’ net retained fuel position.

Operating costs decreased primarily as a result of reduced employee-related costs associated with incentive and benefit plans.

Gain (loss) on sale of assets increased from 2011, due to a $5.7 million gain on the sale of a natural gas pipeline lateral.

Equity earnings from investments decreased due primarily to increased maintenance expenses at Northern Border Pipeline.

	Years Ended December 31,
Operating Information (a)	2013			2012			2011
Natural gas transportation capacity contracted (MDth/d)	5,524			5,366			5,373
Transportation capacity subscribed	90		%	89		%	89		%
Average natural gas price
Mid-Continent region  ($/MMBtu)	$	3.61		$	2.64		$	3.88

(a) - Includes volumes for consolidated entities only.

ONEOK Partners’ natural gas pipelines primarily serve end-users such as natural gas distribution companies and electric-

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generation companies that require natural gas to operate their businesses regardless of location price differentials.  The development of shale gas and other resource areas has continued to increase available natural gas supply and has caused natural gas prices to decrease and location and seasonal price differentials to narrow.  As additional supply is developed, we expect producers to demand incremental services in the future to transport their production to market.  The abundance of shale gas supply and new regulations on emissions from coal-fired electric-generation plants may also increase the demand for ONEOK Partners’ services from electric-generation companies as they convert to a natural gas fuel source.  Conversely, contracted capacity by certain customers that are focused on capturing location or seasonal price differentials may decrease in the future due to narrowing price differentials. Overall, we expect ONEOK Partners’ fee-based earnings to remain relatively stable in the future as the development of shale and other resource areas continue.

In November 2012, the FERC initiated a review of Viking Gas Transmission’s rates pursuant to Section 5 of the Natural Gas Act.  The parties reached agreement on the terms of a settlement that provides for a 2 percent reduction in transportation rates.  The settlement was approved by the FERC in December 2013, and the revised rates became effective January 1, 2014.

The operating information above does not include ONEOK Partners’ 50 percent interest in Northern Border Pipeline.  Substantially all of Northern Border Pipeline’s long-haul transportation capacity has been contracted through June 2015.  In September 2012, Northern Border Pipeline filed with the FERC a settlement with its customers to modify its transportation rates. 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 and cash distributions compared with 2012.

CONTINGENCIES

Gas Index Pricing Litigation - As previously reported, ONEOK and its subsidiary, OESC, along with several other energy companies, are defending multiple lawsuits arising from alleged market manipulation or false reporting of natural gas prices to natural gas-index publications. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit reversed the summary judgments that had been granted in favor of ONEOK, OESC and other unaffiliated defendants in the following cases: Reorganized FLI, Learjet, Arandell, Heartland and NewPage. The Ninth Circuit also reversed the summary judgment that had been granted in favor of OESC on all state law claims asserted in the Sinclair case. The Ninth Circuit remanded the cases back to the United States District Court for the District of Nevada for further proceedings. 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 our legal proceedings is included under Part I, Item 3, Legal Proceedings, in this 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 flows.  Capital expenditures are funded by short- and long-term debt, issuances of equity and operating cash flows.  ONEOK Partners is expected to continue to use these sources for its liquidity and capital resource needs on both a short- and long-term basis, while we expect to rely upon cash distributions received from ONEOK Partners for our liquidity needs in the future.  Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.

ONEOK - In March 2014, we completed the wind down of our energy services business. We expect future cash expenditures associated with the released transportation and storage capacity from the wind down of our energy services business to be

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approximately $80 million on an after-tax basis, which consists of approximately$33 million in 2014, $24 million in 2015, $13 million in 2016 and $10 million during the period from 2017 through 2023.

On January 31, 2014, we completed the separation of ONE Gas. In conjunction with the separation, the following transactions occurred, or are expected to occur in 2014:

• ONE Gas issued senior notes totaling $1.2 billion, generating net proceeds of approximately $1.19 billion;

• We received a cash distribution of approximately $1.13 billion from the proceeds of the ONE Gas senior notes offering;

• We repaid all commercial paper outstanding, which totaled approximately $600.5 million;

• We repaid $150.0 million of senior notes through an early tender;

• We made an irrevocable election to exercise the make-whole call on $400 million of senior notes that we expect to repay in March 2014;

• We reduced our credit facility to $300 million from $1.2 billion; and

• We are terminating our commercial paper program.

As a result of the separation of the natural gas distribution business and the wind down of the energy services business, the cash flow sources and requirements for ONEOK have changed significantly.  ONEOK’s primary source of cash inflows are expected to be distributions to us from our general partner and limited partnership interests in ONEOK Partners. The cash distributions that we expect to receive from ONEOK Partners should provide sufficient resources to finance our operations and quarterly cash dividends. We do not expect any principal debt-service requirements after the first quarter 2014 until our next long-term debt maturity in 2022.

ONEOK Partners - During 2013, ONEOK Partners utilized cash from operations, its commercial paper program and proceeds from its debt and equity issuances to fund its short-term liquidity needs and capital projects. See discussion under “Long-term Financing” for more information.

ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK Partners’ financial condition and credit ratings.  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, we expect ONEOK Partners to fund its future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

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

	December 31, 2013	December 31, 2012
Long-term debt	42%	45%
ONEOK shareholders’ equity	58%	55%
Debt (including notes payable)	49%	54%
ONEOK shareholders’ equity	51%	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 for the periods indicated:

	December 31, 2013	December 31, 2012
Long-term debt	62%	61%
Total equity	38%	39%
Debt (including notes payable)	63%	63%
Total equity	37%	37%

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Stock Repurchase -Our three-year stock repurchase program authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock expired at the end of 2013.

Cash Management -ONEOK and ONEOK Partners each use similar centralized cash management programs that concentrate the cash assets of their operating subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees.  Both centralized cash management programs provide that funds in excess of the daily needs of the operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the respective consolidated groups.  ONEOK Partners’ operating subsidiaries participate in these programs to the extent they are permitted pursuant to FERC regulations or their operating agreements.  Under these cash management programs, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, ONEOK and ONEOK Partners provide cash to their respective subsidiaries or the subsidiaries provide cash to them. 

Separation of Natural Gas Distribution Business - Prior to and in anticipation of the separation, ONE Gas, which at the time was our wholly owned subsidiary, entered into debt and credit agreements. Upon completion of the separation on January 31, 2014, ONEOK’s obligations related to the ONE Gas Credit Agreement and debt issuance discussed below terminated.

ONE Gas Credit Agreement - In December 2013, ONE Gas entered into the ONE Gas Credit Agreement, which became effective upon the separation of the natural gas distribution business on January 31, 2014, and is scheduled to expire in January 2019. The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants including maintaining ONE Gas’ debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. The ONE Gas Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, indebtedness of subsidiary, investments, changes in the nature of business, fundamental changes, transactions with affiliates, burdensome agreements and use of proceeds. In the event of a breach of certain covenants by ONE Gas, amounts outstanding under the ONE Gas Credit Agreement may become due and payable immediately.

The ONE Gas Credit Agreement includes a $50 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 $1.2 billion from $700 million by either commitments from new lenders or increased commitments from existing lenders.  The ONE Gas Credit Agreement is available for general corporate purposes.  The ONE Gas Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in ONE Gas’ credit rating.  Based on ONE Gas’ current credit rating, borrowings, if any, will accrue at LIBOR plus 79.5 basis points, and the annual facility fee is 8 basis points.

ONE Gas Debt Issuance - In January 2014, ONE Gas completed a private placement of three series of Senior Notes aggregating $1.2 billion. ONE Gas received approximately $1.19 billion from the offering, net of issuance costs. ONE Gas made a cash payment to ONEOK of approximately $1.13 billion from the proceeds of the offering.

Short-term Liquidity -ONEOK’s principal source of short-term liquidity will be quarterly distributions from ONEOK Partners. We will have access to our $300 million ONEOK Credit Agreement but do not expect to draw upon the facility. We expect to terminate our commercial paper program.

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 Partners’ revolving credit agreement may be utilized.

At December 31, 2013, the weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.39 percent.  The weighted-average interest rates for the year ended December 31, 2013, on ONEOK’s and ONEOK Partners’ short-term borrowings were 0.43 percent and 0.33 percent, respectively.  Based on the forward LIBOR curve, we expect the interest rates on ONEOK’s and ONEOK Partners’ short-term borrowings to increase in 2014, compared with interest rates on amounts outstanding at December 31, 2013.

ONEOK Credit Agreement - At December 31, 2013, the ONEOK Credit Agreement was available to provide liquidity for working capital and other general corporate purposes.  Amounts outstanding under the commercial paper program reduced 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 December 31, 2013, ONEOK had $564.5 million of commercial paper outstanding, $2.2 million in letters of credit issued under the ONEOK Credit Agreement and approximately $14.8 million of cash and cash equivalents.  ONEOK had approximately $633.3 million of credit available at December 31, 2013, under the ONEOK Credit Agreement. We were in compliance with all covenants of the

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ONEOK Credit Agreement at December 31, 2013.

The ONEOK Credit Agreement was amended, effective upon the separation of our natural gas distribution business on January 31, 2014, and will expire in January 2019. The amendment reduces the size of our credit facility to $300 million from $1.2 billion and contains certain financial, operational and legal covenants.  Among other things, these covenants include maintaining a ratio of indebtedness to Consolidated EBITDA (EBITDA, as defined in our ONEOK Credit Agreement) of no more than 4.0 to 1.  Upon breach of certain covenants by us in our ONEOK Credit Agreement, amounts outstanding under our ONEOK Credit Agreement, if any, may become due and payable immediately.

The ONEOK Credit Agreement, as amended effective January 31, 2014, includes a $50 million sublimit for the issuance of standby letters of credit and a $50 million sublimit for swingline loans.  Under the terms of the ONEOK Credit Agreement, ONEOK may request an increase in the size of the facility to an aggregate of $500 million from $300 million by either commitments from new lenders or increased commitments from existing lenders.  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 ratings, borrowings, if any, will accrue at LIBOR plus 125 basis points, and the annual facility fee is 25 basis points.

In February 2014, ONEOK repaid all commercial paper outstanding and had no borrowings under the amended ONEOK credit facility.

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 December 31, 2013, ONEOK Partners had no commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners Credit Agreement, approximately $134.5 million of cash and approximately $1.2 billion of credit available under the ONEOK Partners Credit Agreement.  As of December 31, 2013, ONEOK Partners could have issued $2.2 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.

In December 2013, ONEOK Partners amended and restated the ONEOK Partners Credit Agreement effective January 31, 2014, to increase the size of the facility to $1.7 billion from $1.2 billion and extended the maturity to January 2019. This amendment includes a $100 million sublimit for the issuance of standby letters of credit, a $150 million swingline sublimit and an option to request an increase in the size of the facility to an aggregate of $2.4 billion from $1.7 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Partners Credit Agreement is available for general partnership purposes. Amounts outstanding under the commercial paper program reduce the borrowing capacity 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.  In 2013, borrowings under the ONEOK Partners Credit Agreement accrued interest at LIBOR plus 130 basis points, and the annual facility fee was 20 basis points based on ONEOK Partners’ current credit rating.  Under the terms of the ONEOK Partners Credit Agreement, as amended in 2014, based on ONEOK Partners’ current credit rating, borrowings, if any, will accrue at LIBOR plus 117.5 basis points, and the annual facility fee is 20 basis points. The ONEOK Partners Credit Agreement is guaranteed fully and unconditionally by ONEOK Partners’ wholly owned subsidiary, the Intermediate Partnership. Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK, and ONEOK does not guarantee ONEOK Partners’ debt, commercial paper or other similar commitments.

The ONEOK Partners Credit Agreement contains certain financial, operational and legal covenants that remained substantially the same with the amendment. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1.  If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter of the acquisition and the two following quarters.  As a result of ONEOK Partners completing the Sage Creek acquisition in the third quarter 2013, and acquiring the remaining 30 percent interest in its Maysville natural gas processing facility in the fourth quarter 2013, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 beginning in the third quarter 2013 and will remain at that level through the second quarter 2014. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners Credit Agreement, amounts outstanding, if any, may become due and payable immediately. At December 31, 2013, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.0 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

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Long-term Financing -We do not expect to issue additional equity or long-term notes, as our next debt maturity is not until 2022 and our operating cash requirements are expected to be funded by cash distributions received from ONEOK Partners. We expect ONEOK Partners 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 involve higher costs or negatively affect their respective credit ratings, among other factors.   Based on ONEOK Partners’ general financial condition, market expectations regarding its future earnings and projected cash flows, and ONEOK Partners’ investment-grade credit rating, ONEOK Partners believes that it will be able to meet its cash requirements and maintain its investment-grade credit ratings.

ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million, 4.25 percent senior notes due 2022.  The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

ONEOK Debt Repayment - In February 2014, we retired approximately $152.5 million, excluding accrued and unpaid interest, of our 4.25 percent senior notes due 2022 through a tender offer. The total amount paid, including fees and other charges, was approximately $150 million.

In February 2014, we made an irrevocable election to exercise the make-whole call on our $400 million, 5.2 percent senior notes due in 2015. The full repayment is expected to occur in March 2014 and is estimated to be approximately $429 million, which includes accrued but unpaid interest to the redemption date.

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.

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 $553.3 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 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 it 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 year ended December 31, 2013, ONEOK Partners sold approximately 681 thousand common units through this program that resulted in net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in ONEOK Partners, of approximately $36.1 million. ONEOK Partners used the proceeds for general partnership purposes.

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As a result of these transactions, our aggregate ownership interest in ONEOK Partners decreased to 41.2 percent at December 31, 2013, from 43.4 percent at December 31, 2012.

In March 2012, ONEOK Partners completed an underwritten public offering of 8.0 million common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million.  ONEOK Partners also sold 8.0 million common units to us in a private placement, generating net proceeds of approximately $460 million.  In conjunction with the issuances, ONEOK Partners GP contributed approximately $19 million in order to maintain our 2 percent general partner interest in ONEOK Partners. ONEOK Partners used the net proceeds from the issuances to repay $295 million of borrowings under its commercial paper program, to repay amounts on the maturity of its $350 million, 5.9 percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures.

Interest-rate Swaps - ONEOK Partners has entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2013 and 2012, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $400 million, which have settlement dates greater than 12 months. In February 2014, ONEOK Partners entered into forward-starting interest-rate swaps with notional amounts totaling $500 million with settlement dates of less than 12 months that were designated as cash flow hedges. 

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 $2.3 billion, $1.9 billion and $1.3 billion for 2013, 2012 and 2011, respectively.  Of these amounts, ONEOK Partners’ capital expenditures were $1.9 billion, $1.6 billion and $1.1 billion for 2013, 2012 and 2011, respectively.  Capital expenditures for 2013 increased, compared with 2012, due primarily to the growth projects in the Natural Gas Gathering and Processing and Natural Gas Liquids segments.

The following table sets forth our 2014 projected capital expenditures, excluding AFUDC:

2014 Projected Capital Expenditures
	(Millions of dollars)
Natural Gas Gathering and Processing	$	1,039
Natural Gas Liquids	883
Natural Gas Pipelines	79
Other	39
Total projected capital expenditures	$	2,040

Unconsolidated Affiliates -The Overland Pass Pipeline Company limited liability company agreement provides that distributions to Overland Pass Pipeline Company’s members are to be made on a pro-rata basis according to each member’s ownership interest.  The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions.  Any changes to, or suspension of, cash distributions from Overland Pass Pipeline Company requires the unanimous approval of the Overland Pass Pipeline Management Committee.  Cash distributions are equal to 100 percent of available cash as defined in the limited liability company agreement.

The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro-rata basis according to each partner’s percentage interest.  The Northern Border Pipeline Management Committee determines the amount and timing of such distributions.  Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon EBITDA, less interest expense and maintenance capital expenditures.  Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement.  

Credit Ratings -ONEOK and ONEOK Partners’ credit ratings as of February 3, 2014, are shown in the table below:

	ONEOK		ONEOK Partners
Rating Agency	Rating	Outlook	Rating	Outlook
Moody’s	Baa3	Stable	Baa2	Stable
S&P	BB+	Stable	BBB	Stable

ONEOK is terminating its commercial paper program following the separation of the natural gas distribution business. ONEOK continues to have access to the ONEOK Credit Agreement, which expires in January 2019.  ONEOK’s rating was

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downgraded to Baa3 by Moody’s and BB+ by S&P in February 2014 to reflect the separation of our natural gas distribution business.

ONEOK Partners’ commercial paper program is rated currently Prime-2 by Moody’s and A-2 by S&P. ONEOK Partners’ credit rating, which currently is investment grade, may be affected by a material change in financial ratios or a material event affecting the business.

If ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under its commercial paper program and credit agreement would increase, and ONEOK Partners potentially could lose access to the commercial paper market.  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 January 2019.  An adverse credit rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement.

In the normal course of business, ONEOK Partners’ counterparties provide secured and unsecured credit.  In the event of a downgrade in ONEOK Partners’ credit ratings or a significant change in ONEOK Partners’ counterparties’ evaluation of our creditworthiness, 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. 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 our financial derivative instruments with contingent features related to credit risk that were in a net liability position at December 31, 2013, was $1.1 million.

Commodity Prices - ONEOK Partners is subject to commodity price volatility.  Significant fluctuations in commodity prices will impact its overall liquidity due to the impact commodity price changes have on its 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. ONEOK Partners believes that its available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility.  See discussion under “Commodity-Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk in our Annual Report, for information on ONEOK Partners’ hedging activities.

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

During 2013, we made no contributions to our defined benefit pension plans, and $11.8 million in contributions to our postretirement benefit plans for both our continuing and discontinued operations.  The contributions to our postretirement benefit plans were attributable to the 2014 plan year.  At December 31, 2013, we expect to make no contributions to our defined benefit pension and postretirement plans in 2014.

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 and for operating cash items that do not impact net income. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain or loss on sale of assets, equity earnings from investments, distributions received from unconsolidated affiliates, deferred income taxes, share-based compensation expense, other amounts, and changes in our assets and liabilities not classified as investing or financing activities.

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

	Years Ended December 31,
	2013			2012			2011
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,294.8		$	984.0		$	1,356.2
Investing activities	(2,642.0		)	(1,814.2		)	(1,371.6		)
Financing activities	912.9			1,339.0			59.2
Change in cash and cash equivalents	(434.3		)	508.8			43.8
Change in cash and cash equivalents included in discontinued operations	2.9			11.5			(13.3		)
Change in cash and cash equivalents from continuing operations	(431.4		)	520.3			30.5
Cash and cash equivalents at beginning of period	577.0			56.7			26.2
Cash and cash equivalents at end of period	$	145.6		$	577.0		$	56.7

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.

2013 vs. 2012 - Cash flows from operating activities, before changes in operating assets and liabilities, were approximately $1,285.4 million in 2013 compared with $1,290.2. million 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 $9.4 million in 2013, compared with a decrease of $306.2 million 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 also was affected 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.

2012 vs. 2011 - Cash flows from operating activities, before changes in operating assets and liabilities, were approximately $1,290.2 million for 2012 compared with $1,367.9 million for 2011.  The decrease was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information.

The changes in operating assets and liabilities decreased operating cash flows $306.2 million for 2012, compared with a decrease of $11.7 million for the same period in 2011.  The change was due primarily to the settlement of interest-rate swaps associated with ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012; and the change in natural gas and natural gas liquids in storage. The change in natural gas and NGLs in storage results from changes in storage levels and the impact of commodity prices on the purchase cost of inventory, both of which vary from period to period. The change in operating assets and liabilities also was affected 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, both of which vary from period to period.

Investing Cash Flows -Cash used in investing activities increased for 2013, compared with 2012, due primarily to increased capital expenditures related to ONEOK Partners’ growth projects as well as expenditures for its Sage Creek acquisition and the remaining 30 percent interest in its Maysville, Oklahoma, natural gas processing facility.

Cash used in investing activities increased for 2012, compared with 2011, due primarily to ONEOK Partners’ growth projects in its natural gas liquids business, offset partially by proceeds from the sale of ONEOK Energy Marketing Company.

Financing Cash Flows - Cash provided by financing activities decreased for 2013, compared with 2012, 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 higher repayment of debt and higher issuance of ONEOK Partners’ common units in 2013. Cash flows also were affected by increased distributions from ONEOK Partners to noncontrolling interests and increased ONEOK dividends in 2013, compared with last year.

Cash provided by financing activities increased for 2012 compared with 2011.  The change is a result of ONEOK’s 2012 debt

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issuance and ONEOK Partners’ 2012 common units issuance. The net cash flows provided by these financing activities were offset partially by the repayment of a scheduled maturity of ONEOK Partners long-term debt, ONEOK’s $150 million share repurchase, increased distributions to noncontrolling interests and increased dividends paid. Financing cash flows also reflect net proceeds from ONEOK Partners’ debt issuances of $1.3 billion in both 2012 and 2011.

REGULATORY AND ENVIRONMENTAL MATTERS

Environmental Matters -ONEOK Partners is 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.

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 and impact analyses and public reviews with respect to such emissions.  At current emissions threshold levels, this rule has had a minimal impact on our existing facilities.  The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

The EPA’s rule on air-quality standards, titled “National Emissions Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, initially included a compliance date in 2013.  Subsequent industry appeals and settlements with the EPA have extended timelines 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.

Additional information about our environmental matters is included in “Environmental and Safety Matters” of Item 1, Business in the Annual Report and Note Q of the Notes to Consolidated Financial Statements in this Current Report.  We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations.  Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters did not have a material impact on earnings or cash flows during 2013, 2012, and 2011.

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. ONEOK Partners continues to participate in financial markets for hedging certain risks inherent in its business, including commodity-price and interest-rate risks. Although the impact to date has not been material, ONEOK Partners’ continues to monitor proposed regulations and the impact the regulations may have on its business and risk-management strategies in the future.

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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 Current 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.

The following is a summary of our most critical accounting policies, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.  We have discussed the development and selection of our estimates and critical accounting policies with the Audit Committee of our Board of Directors.

Fair Value Measurements -We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date.  We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group 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 and over a reasonable period of time using 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 monitoring 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.

The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value.  The levels of the hierarchy are described below:

• Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

• Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date.  Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and

• Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate.  These unobservable inputs are developed based on the best information available and may include our own internal data.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.  Transfers in and out of Level 3 typically result from derivatives for which fair value is determined based on multiple inputs.  If

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prices change for a particular input from the previous measurement date to the current measurement date, the impact could result in the derivative being moved between Level 2 and Level 3, depending upon management’s judgment of the significance of the price change of that particular input to the total fair value of the derivative.

For more information on our fair value measurements, fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk in our Annual Report and Note C of the Notes to Consolidated Financial Statements in this Current Report.

Derivatives, Accounting for Financially Settled Transactions and Risk-Management Activities - 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.

Market value changes result in a change in the fair value of our derivative instruments.  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 nature of the risk being hedged and how effective the hedging instrument is.  When possible, we implement effective hedging strategies using derivative instruments that qualify as hedges for accounting purposes.  If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur.  Commodity price volatility may have a significant impact on the gain or loss in any given period.

To reduce our market risk exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forwards, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate and fuel requirements.  Interest-rate swaps are also used to manage interest-rate risk.  Under certain conditions, we designate these derivative instruments as a hedge against our exposure to changes in fair values or cash flow.  For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings.  Any ineffectiveness of designated hedges is reported in earnings during the period the ineffectiveness occurs. However, if a derivative instrument is ineligible for hedge accounting or if the cash flow hedge is not properly designated, changes in fair value of the derivative instrument would be recorded currently in earnings.  Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings.

For hedges against our exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged. We do not believe that changes in our fair value estimates of our derivative instruments 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.  We assess the effectiveness of hedging relationships quarterly by performing an effectiveness test on our hedging relationships to determine whether they are highly effective on a retrospective and prospective basis.

Upon election, many of our purchase and sale agreements that result in physical delivery and that otherwise would be required to follow the accounting for derivative instruments qualify as normal purchases and normal sales exceptions and are therefore exempt from fair value accounting treatment.

For more information on our derivatives and risk management activities, fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk in our Annual Report and Note D of the Notes to Consolidated Financial Statements in this Current Report for additional discussion.

Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets -We assess our goodwill and indefinite-lived intangible assets for impairment at least annually as of July 1. Our goodwill impairment analysis performed as of July 1, 2013, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.

As a result of the decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment of our former energy services business’ goodwill balance as of March 31, 2012. As a result of that assessment, goodwill with a carrying amount of $10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of $10.3 million recorded in 2012 earnings, which is included in income from discontinued operations. There were no impairment indicators for ONEOK Partners or for our former natural gas distribution business as the cash flows generated from each of these businesses are derived from predominately fee-based, nondiscretionary services.

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There were also no impairment charges resulting from our 2012 or 2011 annual impairment tests.

As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill.  If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment.  In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in step one of the assessment.  If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we will record an impairment charge.

To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective.  Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates.  Under the market approach, we apply multiples to forecasted cash flows.  The multiples used are consistent with historical asset transactions.  The forecasted cash flows are based on average forecasted cash flows over a period of years.

As part of our indefinite-lived intangible asset impairment test, we first assess qualitative factors similar to those considered in the goodwill impairment test to determine whether it is more likely than not that the indefinite-lived intangible asset was impaired. If further testing is necessary, we compare the estimated fair value of our indefinite-lived intangible asset with its book value.  The fair value of our indefinite-lived intangible asset is estimated using the market approach. Under the market approach, we apply multiples to forecasted cash flows of the assets associated with our indefinite-lived intangible asset.  The multiples used are consistent with historical asset transactions.  After assessing qualitative factors, we determined that there were no impairments to our indefinite-lived intangible asset in 2013. There were also no impairment charges resulting from our 2012 or 2011 annual impairment tests.

We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable.  An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.  If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.  We determined that there were no asset impairments in 2013, 2012 or 2011.

For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary.  Therefore, we periodically reevaluate the amount at which we carry our equity method investments to determine whether current events or circumstances warrant adjustments to our carrying value.  We determined that there were no impairments to our investments in unconsolidated affiliates in 2013, 2012 or 2011.

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 of 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 resulted in lower 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.  Bighorn Gas Gathering, in which ONEOK Partners owns a 49 percent equity interest, operates in the dry natural gas formations of the Powder River Basin. Due to declines in natural gas volumes gathered on Bighorn Gas Gathering’s system, ONEOK Partners tested its investment for impairment at December 31, 2013. The carrying amount of ONEOK Partners’ investment as of December 31, 2013, was $87.8 million, which includes $53.4 million in equity method goodwill. ONEOK Partners estimated the fair value of its investment in Bighorn Gas Gathering using an income approach, which discounted the cash flows of ONEOK Partners investment’s underlying assets with a discount rate reflective of its cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures. The fair value exceeded the carrying value; therefore, no impairment was recorded.

A continued decline in volumes in the coal-bed methane areas of the Powder River Basin may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and could result in noncash charges to earnings. A 10 percent decline in the fair value of ONEOK Partners’ investment in Bighorn Gas Gathering would result in a noncash

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impairment charge. For ONEOK Partners’ other equity method investments with operations in the Powder River Basin with carrying values of approximately $204 million, which includes approximately $130 million in equity method goodwill, ONEOK Partners did not identify current events or circumstances that warranted an impairment analysis or an adjustment to its carrying values. ONEOK Partners is not able to reasonably estimate a range of potential future charges, as many of the assumptions that would be used in a fair value model are dependent upon events such as commodity prices, producers’ drilling and production activity and effects of government regulations and policies.

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

See Notes E, F and O of the Notes to Consolidated Financial Statements in this Current Report for our long-lived assets, goodwill and equity-method investments disclosures.

Pension and Postretirement Employee Benefits -We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service.  Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events.  These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods.  In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the costs and liabilities we recognize.  See Note M of the Notes to Consolidated Financial Statements in this Current Report for additional information.

During 2013, we recorded net periodic benefit costs of $64.7 million, of which $21.1 million is included in continuing operations, related to our defined benefit pension plans, and $10.5 million related to postretirement benefits, of which $1.0 million is included in continuing operations.

In connection with the separation of the natural gas distribution business, ONEOK entered into an Employee Matters Agreement with ONE Gas, which provides that employees of ONE Gas no longer participate in benefit plans sponsored or maintained by ONEOK, as of January 1, 2014. The ONEOK defined benefit pension plans and postretirement benefit plans transferred an allocable portion of assets and obligations related to those employees transferring to ONE Gas to newly established trusts for the ONE Gas plans. This resulted in a decrease in ONEOK’s sponsored qualified and nonqualified pension and postretirement plan obligations of approximately $1.1 billion and a decrease in ONEOK’s sponsored pension and postretirement plan assets of approximately $1.0 billion. Additionally, as a result of the transfer of unrecognized losses to ONE Gas, ONEOK’s deferred income taxes and regulatory assets decreased approximately $86.0 million and $331.1 million, respectively.

We estimate that in 2014, we will record net periodic benefit costs of $21.3 million related to our defined benefit pension plans and $0.1 million related to postretirement benefits.

The following table sets forth the weighted-average assumptions used to determine our estimated 2014 net periodic benefit cost related to our defined benefit pension plans, and sensitivity to changes with respect to these assumptions. These sensitivities reflect the decrease in ONEOK’s 2014 net periodic benefit cost compared with 2013 and transfer of the pension plan assets and obligations to ONE Gas as a result of the separation.

	Rate Used	Cost Sensitivity (a)		Obligation Sensitivity (b)
		(Millions of dollars)
Discount rate	5.25%	$	1.5	$	11.1
Expected long-term return on plan assets	7.75%	$	0.6	$	—

(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs.

(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation.

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In determining our 2014 estimated net periodic benefit costs for our postretirement benefits, we assumed a discount rate of 5 percent and an expected long-term return on plan assets of 7.75 percent. A quarter percentage point change in either of the assumed rates would not have a significant impact on our postretirement benefit plan costs or obligation. Assumed health care cost-trend rates have an effect on the amounts reported for our postretirement benefit plans.  A one percentage point change in assumed health care cost trend rates would have the following effects:

	One Percentage Point Increase		One Percentage Point Decrease
	(Millions of dollars)
Effect on total of service and interest cost	$	0.6	$	(0.5	)
Effect on postretirement benefit obligation	$	2.4	$	(2.2	)

During 2013, we made no contributions to our defined benefit pension plans and $11.8 million in contributions to our postretirement benefit plans related primarily to our discontinued operations.  The contributions to our postretirement benefit plans were attributable to the 2014 plan year.  At December 31, 2013, we expect to make no contributions to our defined benefit pension and postretirement plans in 2014.

Contingencies -Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures.  We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated.  We expense legal fees as incurred and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study.  Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.  Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows during 2013, 2012 and 2011.  Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.  See Note Q of the Notes to Consolidated Financial Statements in this Current Report for additional discussion of contingencies.

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2013. For additional discussion of the debt and operating lease agreements, see Notes H and Q, respectively, of the Notes to the Consolidated Financial Statements in this Current Report. The table below includes the contractual obligations of our former energy services business as ONEOK remains responsible for those obligations. The table below does not include the obligations of our former natural gas distribution business as those obligations have been transferred to, and are now the responsibility of, ONE Gas as of the separation on January 31, 2014.

	Payments Due by Period
Contractual Obligations	Total		2014		2015		2016		2017		2018		Thereafter
ONEOK	(Millions of dollars)
Commercial paper	$	564.5	$	564.5	$	—	$	—	$	—	$	—	$	—
Long-term debt	1,689.0		3.0		403.0		3.0		3.0		3.0		1,274.0
Interest payments on debt	953.0		87.1		75.7		65.9		65.8		65.6		592.9
Operating leases	2.6		1.2		0.8		0.4		0.2		—		—
Energy Services firm transportation and storage contracts	137.2		61.2		38.6		19.9		9.7		4.0		3.8
Financial and physical derivatives	280.2		280.2		—		—		—		—		—
Employee benefit plans	27.0		—		7.0		11.0		9.0		—		—
ONEOK total	$	3,653.5	$	997.2	$	525.1	$	100.2	$	87.7	$	72.6	$	1,870.7
ONEOK Partners
ONEOK Partners senior notes	$	6,000.0	$	—	$	—	$	1,100.0	$	400.0	$	425.0	$	4,075.0
Guardian Pipeline senior notes	67.2		7.7		7.7		7.7		7.7		7.7		28.7
Interest payments on debt	4,622.7		315.8		315.2		278.4		263.2		252.6		3,197.5
Operating leases	3.9		2.0		0.5		0.3		0.2		0.2		0.7
Firm transportation and storage contracts	104.0		18.4		16.3		14.4		12.8		11.9		30.2
Financial and physical derivatives	124.6		124.6		—		—		—		—		—
Purchase commitments, rights of way and other	495.2		87.3		74.5		74.6		74.5		74.5		109.8
ONEOK Partners total	$	11,417.6	$	555.8	$	414.2	$	1,475.4	$	758.4	$	771.9	$	7,441.9
Total	$	15,071.1	$	1,553.0	$	939.3	$	1,575.6	$	846.1	$	844.5	$	9,312.6

Commercial paper - All commercial paper obligations were repaid with a portion of the approximately $1.13 billion cash proceeds we received from ONE Gas in connection with the separation.

Long-term debt - Long-term debt as reported in our Consolidated Balance Sheets includes unamortized debt discount and the unamortized settlement values of interest-rate swaps. In February 2014, we repaid $150 million, excluding accrued and unpaid interest, of our 4.25 percent notes due 2022 through a tender offer. In February 2014, we made an irrevocable election to exercise the make-whole call on our $400 million 5.2 percent notes due in 2015. The full repayment is expected to occur in March 2014 with the total estimated to be approximately $429 million, which includes accrued but unpaid interest to the redemption date.

Interest payments on debt - Interest expense is calculated by multiplying long-term debt by the respective coupon rates, adjusted for active swaps. These amounts are expected to be reduced by $80.5 million in total due to the early extinguishment of long-term debt noted above.

Operating leases - Our operating leases include leases for office space, pipeline equipment and vehicles.

Energy Services firm transportation and storage contracts - These obligations include amounts related to contracts that expire by March 31, 2014, and future payments obligations related to released contracts. See additional information in Note B in the Notes to the Consolidated Financial Statements in this Current Report.

Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments, physical and financial commodity derivatives.  Estimated future variable-price purchase commitments are based on market information at December 31, 2013.  Actual future variable-price purchase commitments may vary depending on market prices at the time of delivery.  Not included in these amounts are offsetting cash inflows from ONEOK Partners’ product sales and net positive settlements. As market information changes daily and is potentially volatile, these values may change significantly. Additionally, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these

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amounts.

Employee benefit plans - Employee benefit plans include our anticipated contributions to our pension and postretirement benefit plans for 2014.  See Note M of the Notes to Consolidated Financial Statements in this Current Report for discussion of our employee benefit plans.

Purchase commitments, rights of way and other - Purchase commitments include commitments related to ONEOK Partners’ growth capital expenditures and other rights-of-way and contractual commitments.  Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Current Report are forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended.  The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flow and projected levels of dividends), liquidity, management’s plans and objectives for our future growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), 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 Current Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Current 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 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 climate change;

• 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

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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 any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, 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;

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

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

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

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

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

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

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

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

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

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

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

• the impact of potential impairment charges;

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

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

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

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

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